ALABAMA POWER COMPANY,3 3. Petitioner proposes to construct and install combined cycle generating...

ALABAMA POWER COMPANY,

Petitioner

PETITION: For a certificate of convenience and necessity for: (i) the construction and installation of combined cycle generating capacity at the site of Petitioner’s Barry Steam Plant located in Mobile County, Alabama; (ii) the acquisition of existing combined cycle generating capacity in Autauga County, Alabama; (iii) the acquisition of rights and the assumption of payment obligations under a power purchase agreement for the output of combined cycle generating capacity operated in Mobile County, Alabama; and (iv) the acquisition of rights and the assumption of payment obligations under power purchase agreements for the output from five solar photovoltaic and battery energy storage systems, located in Calhoun, Chambers, Dallas, Houston and Talladega Counties; together with all transmission arrangements, structures, substations, and facilities, environmental control measures, facilities or arrangements for the handling, treatment, transportation, delivery and processing of fuel, and any and all other appliances, appurtenances, facilities, rights, equipment, acquisitions, commitments and accounting authorizations necessary for or incident thereto.

Docket No. __________

TO THE ALABAMA PUBLIC SERVICE COMMISSION:

Alabama Power Company (“Petitioner” or “Company”) hereby requests, pursuant to

Alabama Code § 37-4-28 and Parts A and B of Rate CNP–Adjustment for Commercial

Operation of Certificated New Plant, that the Commission issue an order in this proceeding

granting a certificate of convenience and necessity (“Certificate”). By the Certificate, as

described in this Petition and in the testimony and exhibits filed in support thereof, the

Commission would authorize the Company to: (i) construct and install combined cycle

generating capacity at the site of the Petitioner’s Barry Steam Plant located in Mobile County,

2

Alabama; (ii) acquire the Central Alabama Generating Station, a combined cycle generating

facility located in Autauga County, Alabama; (iii) acquire rights and assume payment obligations

under a power purchase agreement (“PPA”) pertaining to the Hog Bayou Energy Center, a

combined cycle generating facility located in Mobile County, Alabama; and (iv) acquire rights

and assume payment obligations under five PPAs pertaining to solar photovoltaic facilities, each

being paired with a battery energy storage system (“BESS”), as located in Calhoun, Chambers,

Dallas, Houston and Talladega Counties. In addition to the requested authority under the

Certificate, the Company is seeking authorization to pursue approximately 200 MW of demand-

side management and distributed energy resource programs.

In support of its Petition, the Company states as follows:

1. Petitioner is a corporation organized and existing under the laws of the State of

Alabama that owns and operates electric generating plants and has other sources of supply of

electric power, all of which are connected by or delivered to transmission lines and facilities

forming the Company’s interconnected electrical system. Petitioner is engaged as a public utility

in the distribution and sale to the public of the electricity so produced and acquired by it, and

such utility service is furnished by Petitioner to the public in a large section of the State.

2. In order to meet the demand for electricity in the territory served by the Company

and to render adequate and reliable service to the public, as contemplated under Title 37 of the

Code of Alabama, it is necessary and appropriate for the Company to make the following

additions to its portfolio of supply resources.1

1 The Company’s reliability-based need for additional resources is addressed in the supporting testimony and exhibits of John B. Kelley and Jeffrey B. Weathers.

3

3. Petitioner proposes to construct and install combined cycle generating capacity at

the site of Petitioner’s Barry Steam Plant located in Mobile County, Alabama (“Barry Unit 8”).2

Barry Unit 8 will initially provide approximately 726 MW of winter-rated capacity (increasing to

approximately 743 MW of winter-rated capacity under a subsequent uprate), with an expected

useful life of 40 years. Commercial operation is expected in November, 2023. The principal

components of Barry Unit 8 include one Mitsubishi 501 J-series air-cooled combustion turbine,

one heat recovery steam generator with duct firing, and one condensing reheat steam turbine

(together comprising a 1-on-1 combined cycle configuration), along with other balance of plant

equipment, including a cooling tower for closed-cycle cooling operations. The unit will be

constructed under a turnkey Agreement for Engineering, Procurement and Construction with

Mitsubishi Hitachi Power Systems Americas, Inc. and Black & Veatch Construction, Inc. The

project will take maximum advantage of existing infrastructure at the Plant Barry site, but some

infrastructure additions will be required, such as a new tie line to the existing adjacent Ellicott

230 kV substation, a gas extension line from the existing Plant Barry gas yard to the location of

the new unit, and new water lines and access roads.

4. Petitioner proposes to acquire the Central Alabama Generating Station (“Central

Alabama”) located in Autauga County, Alabama.3 Central Alabama is a combined cycle facility

constructed in 2003, with an estimated remaining life (post-closing) of approximately 23 years.

The facility, which has a winter capacity rating of 915 MW and a summer capacity rating of 890

MW, is owned by Tenaska Alabama II Partners, L.P. (the “Partnership”), a Delaware limited

partnership in which a Tenaska subsidiary is the managing general partner and majority owner.

2 Barry Unit 8 is addressed in the supporting testimony and exhibits of Michael A. Bush.

3 The acquisition of Central Alabama, as well as the associated PPA that expires in mid-2023, is addressed in the supporting testimony and exhibits of John B. Kelley.

4

Upon the closing of a Purchase and Sale Agreement, the Company will hold a 100 percent

interest in the Partnership, after which all rights, title and interest of the Partnership in its assets

(Central Alabama, along with related assets and properties) will be transferred into Petitioner.

Until May 2023, Central Alabama is subject to a PPA with a third party under which the third

party is entitled to the capacity of the facility and the associated energy. The third-party PPA will

remain in place until it expires, with the Company entitled to receive the associated revenues.

Petitioner will thereafter have the same rights and responsibilities associated with Central

Alabama as with any other generating facility that it owns.

5. Petitioner proposes to acquire rights and assume payment obligations under a

PPA with Mobile Energy, LLC whereby the Company will be entitled to the entire capability of

the Hog Bayou Energy Center located in Mobile County, Alabama, for a total term of

approximately 19 years.4 The Hog Bayou Energy Center is a combined cycle, natural-gas fired

facility with a summer rating of 222 MW and a winter rating of 238 MW. In order to address

certain near-term reliability needs of the Company, the PPA calls for an early start period

beginning in 2020 through November 2023, followed by a 15-year term beginning in December

2023. Along with monthly capacity payments, the Company is responsible for an energy

payment that includes a charge for each unit start, plus a charge for variable O&M expenses and

a fuel adjustment based on a guaranteed heat rate. As this is a “tolling” PPA, the Company is

separately responsible for the fuel-related arrangements (commodity and transportation).

6. Petitioner proposes to acquire rights and assume payment obligations under 28-

year PPAs with five separate projects to be located in Calhoun, Chambers, Dallas, Houston and

4 The PPA associated with the Hog Bayou Energy Center is addressed in the supporting testimony and exhibits of John B. Kelley.

5

Talladega Counties.5 Each project comprises a nominal 80 MW solar photovoltaic facility and a

nominal 80 MW BESS that, given operational parameters, yield a cumulative winter capacity

equivalence of 340 MW (68 MW per project). Although the payment structure for each of these

five PPAs bundles both solar- and BESS-related costs into a single combined energy payment, a

portion of that combined energy payment is attributable to the cost of the BESS component that

provides capacity to the Company.

7. Along with the above-described supply resources, Petitioner is requesting

authorization to pursue 200 MW in additional demand-side management and distributed energy

resource programs.6 Petitioner contemplates submitting them to the Commission on a program-

by-program basis, with approval contingent on a reasonable demonstration that the project

results in positive benefit for all customers over its term. This demonstration would take into

account the costs and revenue impacts of the project and the expected value corresponding to an

avoided generic capacity addition, along with other positive benefits that may accrue through

load growth, load retention or other relevant considerations associated with the particular project.

8. Petitioner states that the described generating units and PPAs, together with all

transmission arrangements, structures, substations, and facilities, environmental control

measures, facilities or arrangements for the handling, treatment, transportation, delivery and

processing of fuel, and any and all other appliances, appurtenances, facilities, rights, equipment,

acquisitions, commitments and accounting authorizations necessary for or incident thereto, are

5 These solar/BESS projects and the associated PPAs are addressed in the supporting testimony and exhibits of John B. Kelley.

6 These additional demand-side management and distributed energy resource programs are addressed in the supporting testimony of John B. Kelley.

6

necessary, advantageous, efficient and appropriate for the purposes aforesaid and are in the

public interest.7

9. Petitioner states that the costs associated with the portfolio of resources described

in this Petition will be recovered through cost recovery mechanisms established by the

Commission (specifically, Rate CNP–Adjustment for Commercial Operation of Certificated New

Plant, Rate ECR–Energy Cost Recovery Rate, and Rate RSE–Rate Stabilization and Equalization

Factor), together with such accounting authorizations, directions and clarifications from the

Commission as needed in the circumstances.8

WHEREFORE, Petitioner requests that this Commission, after a public hearing of all

parties interested at a time and place fixed by the Commission, grant to the Company a

certificate of convenience and necessity pursuant to the provisions of Alabama Code § 37-4-28

(1975) and Parts A and B of Rate CNP–Adjustment for Commercial Operation of Certificated

New Plant, approving and authorizing the portfolio of resources set forth in this Petition, together

with all transmission arrangements, structures, substations, and facilities, environmental control

measures, facilities or arrangements for the handling, treatment, transportation, delivery and

processing of fuel, and any and all other appliances, appurtenances, facilities, rights, equipment,

acquisitions, commitments and accounting authorizations necessary for or incident, and that the

Commission make and enter such further orders as may be necessary or appropriate.

7 The cost-effectiveness of the proposed portfolio of generating resources and the manner by which that determination was made are addressed in the supporting testimony and exhibits of John B. Kelley and M. Brandon Looney.

8 The timing and manner by which costs associated with the proposed generating resources would be recovered, along with associated accounting authorizations, are explained in detail in the supporting testimony of Christine M. Baker. The regulatory process associated with the demand-side management and distributed energy resource programs is addressed in the testimony of John B. Kelley.

BEFORE THE ALABAMA PUBLIC SERVICE COMMISSION

Alabama Power Company

Direct Testimony of Alabama Power Company (Public Version)

VOLUME I

John B. Kelley Testimony and Exhibits

Jeffrey B. Weathers Testimony and Exhibit

Michael A. Bush Testimony and Exhibit

M. Brandon Looney Testimony and Exhibit

Christine M. Baker Testimony and Exhibit

PETITION: For a certificate of convenience and necessity for: (i) the construction and installation of combined cycle generating capacity at the site of Petitioner’s Barry Steam Plant located in Mobile County, Alabama; (ii) the acquisition of existing combined cycle generating capacity in Autauga County, Alabama; (iii) the acquisition of rights and the assumption of payment obligations under a purchased power agreement for the output of combined cycle generating capacity operated in Mobile County, Alabama; and (iv) the acquisition of rights and the assumption of payment obligations under purchased power agreements for the output from five solar photovoltaic and battery energy storage systems, located in Calhoun, Chambers, Dallas, Houston and Talladega Counties; together with all transmission arrangements, structures, substations, and facilities, environmental control measures, facilities or arrangements for the handling, treatment, transportation, delivery and processing of fuel, and any and all other appliances, appurtenances, facilities, rights, equipment, acquisitions, commitments and accounting authorizations necessary for or incident thereto.

Docket No. ___________

1 | P a g e


ALABAMA POWER COMPANY ) PETITION )

Petitioner ) ) Docket No. ________

DIRECT TESTIMONY OF JOHN B. KELLEY ON BEHALF OF ALABAMA POWER COMPANY

Q. STATE YOUR NAME AND BUSINESS ADDRESS. 1

A. My name is John B. Kelley and my business address is 600 North 18th Street, 2

Birmingham, Alabama. 3

Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY? 4

A. I am employed by Alabama Power Company (“Alabama Power” or “Company”) as 5

Director of Forecasting and Resource Planning. 6

Q. DESCRIBE THE PRINCIPAL BUSINESS ACTIVITY OF ALABAMA POWER.7

A. Alabama Power is a public utility company, organized and existing under the laws of the 8

State of Alabama. Alabama Power operates an integrated electric utility system across a 9

large portion of the State. To this end, the Company’s primary business activities are the 10

generation, transmission and distribution of electricity to the public. 11

Q. BRIEFLY SUMMARIZE YOUR EDUCATIONAL BACKGROUND AND 12

PROFESSIONAL EXPERIENCE.13

A. I graduated from the University of Illinois in 1983 with a Bachelor of Science in 14

Electrical Engineering degree. In 1987, I received a Master of Business Administration 15

degree from the University of Alabama at Birmingham. I began my career with Southern 16

Company in 1983 as an engineer in the transmission planning department of Southern 17

PUBLIC VERSION

2 | P a g e

Company Services, Inc. (“SCS”). My responsibilities increased in the generation 1

planning and integrated resource planning departments, including a two-year consulting 2

project for the former Southern Electric International. In 1990, I began working for 3

Alabama Power in the marketing department, where I maintained supervisory 4

responsibilities over project analysis. I later served as the Manager of Marketing 5

Services within the Alabama Power retail marketing organization, with responsibilities 6

that included the development of retail market plans, economic evaluations, and mass 7

marketing programs. I was named Director of Forecasting and Resource Planning in 8

2008. 9

Q. WHAT ARE YOUR JOB DUTIES AND RESPONSIBILITIES?10

A. As Director of Forecasting and Resource Planning, I am responsible for the Company’s 11

Integrated Resource Plan (“IRP”), which includes the identification of timely and cost-12

effective expansions of Alabama Power’s resources, such as generation additions, long-13

term power purchases, demand-side options, and renewable energy and environmentally-14

specialized generating resources. In addition, I have responsibility for the development 15

of Alabama Power’s demand, energy, customer and revenue forecasts. 16

Q. ARE YOU FAMILIAR WITH THE COMPANY’S PLANS FOR THE RESOURCE 17

ADDITIONS DESCRIBED IN THE PETITION FOR A CERTIFICATE OF 18

CONVENIENCE AND NECESSITY? 19

A. Yes. 20

Q. HAVE YOU READ THE PETITION FILED BY THE COMPANY IN THIS 21

PROCEEDING?22

A. Yes. 23

PUBLIC VERSION

3 | P a g e

Q. ARE THE STATEMENTS CONTAINED IN THE PETITION TRUE AND 1

CORRECT TO THE BEST OF YOUR KNOWLEDGE, INFORMATION AND 2

BELIEF? 3

A. Yes. 4

Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 5

A. The purpose of my testimony is basically three-fold, and is organized accordingly. First, 6

I will discuss the IRP process used by the Company to determine the need for new 7

capacity resources in order to continue to provide reliable service to customers. I will 8

then overview how Alabama Power identified potential resource opportunities for 9

evaluation, including the Request for Proposals (“RFP”) process that was used to 10

determine the availability of reliable and cost-effective capacity alternatives from the 11

wholesale market. Finally, I will summarize the proposed resource additions that the 12

Company has selected for certification as providing reliable service at the lowest 13

practicable total cost (capacity and energy) over the long run. I also will discuss the 14

Company’s request for authorization to pursue 200 megawatts (“MW”) of demand-side 15

management and distributed energy resource programs. 16

Q. ARE OTHER WITNESSES ALSO TESTIFYING IN SUPPORT OF THE 17

COMPANY’S PETITION? 18

A. Yes. In addition to my testimony, the Company is offering the testimony of Jeffrey B. 19

Weathers, Michael A. Bush, M. Brandon Looney and Christine M. Baker. 20

Q, BRIEFLY DESCRIBE THE TOPICS ADDRESSED BY THOSE OTHER 21

WITNESSES. 22

PUBLIC VERSION

4 | P a g e

A. Mr. Weathers will discuss the latest reserve margin study, which confirms the significant 1

shift in reliability risk from the summer season to the winter season and the associated 2

use of seasonal planning by the Company. Mr. Weathers also discusses the adoption of a 3

winter target reserve margin in addition to the summer target reserve margin.4

Mr. Bush describes the development of the Company’s turnkey option at the Plant 5

Barry site, which will be accomplished through an agreement between the Company and 6

Mitsubishi Hitachi Power Systems Americas, Inc. and Black & Veatch Construction, Inc.7

for the associated engineering, procurement and construction. 8

Mr. Looney overviews the processes used to evaluate the various options 9

available to meet the Company’s reliability needs and determine which ones would 10

comprise the most cost-effective portfolio of resource additions. 11

Finally, Ms. Baker will address how various rate mechanisms and accounting 12

authorizations will apply to the components of the proposed resource portfolio. 13

Q. WHAT IS THE RELATIONSHIP BETWEEN THE COMPANY AND THE 14

OTHER OPERATING COMPANIES OF THE SOUTHERN ELECTRIC SYSTEM 15

WITH REGARD TO GENERATION PLANNING AND SYSTEM OPERATION? 16

A. The Company and the other operating companies of the Southern electric system operate 17

their systems on a coordinated basis in order to achieve economies of scale and other 18

available efficiencies. The Intercompany Interchange Contract (“IIC”), which is a rate 19

schedule filed with and approved by the Federal Energy Regulatory Commission, 20

governs the treatment of and accounting for: (i) temporary surpluses and deficits of 21

capacity among the companies; and (ii) energy exchanges and corresponding settlements 22

associated with the economic dispatch of the system power pool. Operating in this 23

PUBLIC VERSION

5 | P a g e

manner under the IIC lowers total production cost and enhances system reliability, which 1

benefits all of the operating companies. In addition, the long-term load forecasts of the 2

individual operating companies are combined into a single integrated forecast, which 3

enables them to benefit from system diversity through reserve margins that are lower than 4

would be required were each to operate on a stand-alone basis. 5

For the affiliated retail operating companies, the resource additions necessary to 6

provide reliable and economic service are determined through a comprehensive and 7

coordinated resource planning process. Using long-term planning reserve margin 8

guidelines, the process determines the amount of capacity, and indicates the type of 9

resource additions, required to provide reliable, efficient and economical service. It 10

should be emphasized that, although engaging in coordinated planning and operation, 11

each retail operating company retains the right and bears the responsibility to determine 12

the resource additions appropriate for its service territory and to operate its system so as 13

to satisfy the needs of its customers in a reliable and efficient manner. The expectation 14

that each operating company will have resources to reliably serve its own customers, 15

which I understand to be an integral part of Alabama Power’s status as a public utility 16

under Alabama law, is likewise a fundamental premise embodied the IIC. 17

I. IRP Process and Indicated Resource Need 18

Q. WHAT IS THE PURPOSE OF THE IRP PROCESS AND HOW IT IS USED BY 19

THE COMPANY?20

A. The IRP process is an analytical tool designed to identify the timing, amount, and types 21

of resources necessary to serve the long-term expected energy and demand requirements 22

of Alabama Power’s customers. It involves choosing from a broad range of resource 23

PUBLIC VERSION

6 | P a g e

options to produce an indicative benchmark plan of resource additions that is reasonably 1

expected to meet anticipated load obligations (including an appropriate reserve margin) at 2

the lowest practicable cost over the long run. These results help guide the Company as it 3

undertakes to develop and implement a supply-side and demand-side resource strategy 4

that will enable it to continue to provide service that is reliable and cost effective for 5

customers. 6

Q. CAN THE IRP PROCESS BE REDUCED TO WRITING? 7

A. Integrated resource planning is not a document, but rather a comprehensive, data-8

intensive process. The Company does, however, develop a summary report that provides 9

considerable detail regarding the objectives of the IRP process, the major steps, tools, and 10

inputs it employs, and other considerations that together produce the indicative 11

benchmark plan of future resource additions. A copy of the public version of the 2019 12

IRP Summary Report is appended to my testimony as Exhibit JBK-1. 13

Q. WAS THIS EXHIBIT PREPARED UNDER YOUR DIRECTION AND 14

SUPERVISION? 15

A. Yes. The Forecasting and Resource Planning organization that I oversee is responsible 16

for implementing the Company’s IRP process, including the preparation of this 2019 IRP 17

Summary Report. 18

Q. BRIEFLY OVERVIEW THE COMPANY’S IRP PROCESS. 19

A. As described more fully in the 2019 IRP Summary Report, the IRP is an iterative process 20

that evaluates existing and potential resource options to identify the best combination of 21

needed additions, in terms of reliability and expected total cost for serving customers. 22

Using updated marginal cost projections to capture significant changes related to fuel, 23

PUBLIC VERSION

7 | P a g e

technology, regulatory compliance and other such factors, the Company evaluates its 1

existing supply-side options to determine what, if any, resource additions or 2

modifications are economically viable. Similarly, the Company uses the same marginal 3

cost approach to evaluate demand-side management (“DSM”) programs to determine 4

those that appear cost-effective and thus eligible for inclusion in a new benchmark plan. 5

These results, along with comparable analyses applied to new candidate technologies, are 6

integrated to produce an optimum combination of demand-side and supply-side resources 7

that comprise the benchmark plan. This benchmark plan shows additions that, together 8

with the Company’s existing portfolio of resources, will meet the projected demand and 9

energy needs of the Company’s customers in a reliable and cost-effective manner. 10

Q. HOW IS THE AMOUNT AND TIMING OF THE RESOURCE NEED 11

DETERMINED? 12

A. The determination of the amount and timing of the needed resources starts with an update 13

to the Company’s forecast of future energy and peak demand requirements for the next 14

20 years. Based on this updated load forecast, the Company identifies a schedule of 15

resources required to serve that load reliably, which necessarily includes an appropriate 16

reserve margin. 17

Q. WHAT IS THE PURPOSE OF A RESERVE MARGIN? 18

A. Electric utility customers expect and depend on a high level of service reliability. 19

Accordingly, a retail electric utility like Alabama Power must have an economically 20

balanced margin of generating capacity above its anticipated peak load, i.e., a reserve 21

margin. This enables the Company to maintain sustained reliability for its customers, 22

notwithstanding unpredictable events such as equipment failures or extreme weather. 23

PUBLIC VERSION

8 | P a g e

Q. HOW WERE THE RESERVE MARGINS USED IN THE COMPANY’S 2019 IRP 1

DETERMINED? 2

A. The reserve margins used by the Company are based on the 2018 Reserve Margin Study 3

that analyzed the reliability challenges on the system and then identified risk-adjusted 4

reserve margins that would minimize the combined costs of maintaining reserve capacity, 5

system production costs, and customer costs associated with service interruptions. The 6

2018 Reserve Margin Study is addressed in the testimony of Mr. Weathers, including a 7

discussion of the underlying methodology and the increased reliability risk in the winter. 8

Winter-related reliability issues are also addressed in the 2019 IRP Summary Report. 9

The confirmation in the 2018 Reserve Margin Study of a significant increase in 10

winter reliability risks (as identified in the preceding 2015 Reserve Margin Study) led the 11

Company (along with the other operating companies) to begin using seasonal planning in 12

the IRP process. This means that, while in the past the Company has historically relied 13

upon a target reserve margin only for the summer season, it is now using independent 14

evaluations of resource adequacy in both the summer and the winter peak periods to 15

ensure that system reliability is fully addressed year round. This results in the 16

establishment of separate target reserve margins for each of those seasons. 17

Q. HAS THE COMPANY SEEN CHANGES IN THE LOADS OF ITS CUSTOMERS 18

THAT FURTHER VALIDATE THE ADOPTION OF SEASONAL PLANNING? 19

A. Yes. Alabama Power has traditionally been considered summer peaking, meaning its 20

annual peak demand has occurred during the summer months. However, in recent years, 21

Alabama Power’s winter peak demand has exceeded the summer peak demand. The 22

2014 actual winter peak was 12,610 MW, which exceeded the prior all-time peak of 23

PUBLIC VERSION

9 | P a g e

12,496 MW that occurred in the summer of 2007. Moreover, on a weather-normalized 1

basis, the Company’s winter peak has exceeded its summer peak since 2010, and the 2

Company’s most recent load forecast continues to project a winter peak demand that is 3

higher than the summer peak demand. 4

Q. DO THE RESERVE MARGINS THAT UNDERLIE THE 2019 IRP REFLECT 5

THESE SEASONAL REALITIES? 6

A. Yes. The Company is maintaining the current 16.25 percent long-term system target 7

reserve margin for the summer peak planning season. To address the winter reliability 8

concerns, the Company is adding a long-term winter target reserve margin of 26 percent 9

for the system, to be used in planning for the winter peak season. 10

Q. DOES THIS MEAN THAT THE COMPANY MUST HAVE RESERVE MARGINS 11

AT BOTH OF THOSE LEVELS TO MAINTAIN RELIABIITY IN THE 12

RESPECTIVE SEASONS? 13

A. No. As previously explained, Alabama Power and the other operating companies of the 14

Southern electric system operate on a coordinated basis in order to achieve economies of 15

scale and other available efficiencies. One of the recognized advantages of operating in 16

this manner is the benefit of system diversity, enabling the individual companies to 17

maintain lower “diversified” reserve margins while collectively achieving the higher 18

target reserve margin for the system. Thus, for purposes of long-term planning, Alabama 19

Power’s diversified summer target reserve margin is 14.89 percent and its diversified 20

winter target reserve margin is 25.25 percent. 21

PUBLIC VERSION

10 | P a g e

Q. HAS THE ALABAMA PUBLIC SERVICE COMMISSION (“COMMISSION”) 1

HAD OCCASION TO REVIEW AND ADDRESS THE IRP PROCESS USED BY 2

THE COMPANY? 3

A. Yes. The Company has used integrated resource planning for many years and the 4

resulting IRPs have prompted a number of petitions for certification of new resources to 5

satisfy a reliability-based need for additional capacity. On several of those occasions, the 6

Commission has specifically endorsed that process. 7

Q. DID THE COMPANY FOLLOW THAT SAME PROCESS TO DETERMINE THE 8

RESOURCE NEEDS REFLECTED IN THE CURRENT PETITION? 9

A. Yes. As one would expect, inputs to the IRP (such as marginal cost projections, load 10

forecasts, target reserve margins, and candidate technologies) are revised and updated 11

over time, but from a conceptual and methodological standpoint, the Company continues 12

to apply the same fundamental IRP process previously endorsed by the Commission. To 13

keep the Commission apprised of the ongoing status of the IRP process, the Company 14

provides to Commission staff its periodic IRP results (typically performed at three-year 15

intervals) and meets with staff to review and discuss the results, including changes in the 16

underlying drivers. 17

Q. WHAT ARE THE CAPACITY NEEDS INDICATED BY THE IRP FOR THE 18

RESPECTIVE SEASONS? 19

A. Over the next ten years, the 2019 IRP shows the Company is within its diversified target 20

for the summer season. In the winter, however, the Company’s (“APC”) reserve margins 21

are below the applicable target, 22

.23

PUBLIC VERSION

11 | P a g e

Capacity Need (MW) - Winter Year APC Reserve Margin (%) APC Need (MW)

2020

2021

2022

2023

2024

2025

2026

2027

2028

1

These results demonstrate that, , Alabama Power has a 2

reliability-driven need for additional resources in the winter. 3

Q. WHAT CAUSES THE INDICATED AMOUNT OF NEED TO SOMETIMES 4

MOVE DOWN FROM ONE YEAR TO THE NEXT? 5

A. Typically, the amount of need will move up gradually in response to normal load growth. 6

In some years, however, there can be a larger shift, either in the Company’s projected load 7

(due, for example, to a new or expiring contract) or in its available resources (due, for 8

example, to a unit addition, expiration of a power purchase agreement, or unit 9

unavailability assumptions). 10

Q. DO THE SYSTEM RESERVE MARGINS, WHICH REFLECT ALABAMA 11

POWER’S OBLIGATIONS AND RESOURCES ALONG WITH THOSE OF THE 12

OTHER RETAIL OPERATING COMPANIES, INDICATE SUCH A CAPACITY 13

SHORTFALL IN THE WINTER OVER THIS SAME PERIOD? 14

PUBLIC VERSION

12 | P a g e

A. No. When viewed on a coordinated system basis, the reserve margins and indicated 1

capacity additions needed to satisfy the long-term winter planning reserve margin over 2

the 2020-2028 timeframe are as follows.13

2019 IRP

Winter Benchmark Base Case with Generic Additions Year APC CT's APC CC's APC RM APC NEEDS (MW) ROC RM ROC NEEDS (MW)

2020 - -

2021 - -

2022 - -

2023 300 -

2024 - -

2025 - 900

2026 - -

2027 600 -

2028 300 270

4

Q. WHY DOES ALABAMA POWER HAVE LARGE WINTER CAPACITY NEEDS 5

OVER THIS TIMEFRAME, WHEREAS THE COLLECTIVE SOUTHERN 6

SYSTEM DOES NOT? 7

A. These capacity needs arise for Alabama Power because its load peaks in the winter 8

season. In contrast, the largest of the retail operating companies, Georgia Power, 9

continues to experience its peak load in the summer. The fact that Georgia Power does 10

so, coupled with its size relative to the other companies, is the reason the winter need 11

shown for the collective system is considerably less, as Georgia Power currently has 12

capacity on its system that can be used to help support the winter requirements of 13

Alabama Power’s customers. 14

1 For purposes of this table, “CT” means combustion turbine, “CC” means combined cycle, “ROC” means retail operating companies, and “RM” means reserve margin.

PUBLIC VERSION

13 | P a g e

Q. GIVEN THE COORDINATED OPERATIONS OF THE SOUTHERN SYSTEM, 1

WHY DOESN’T ALABAMA POWER RELY ON CAPACITY OF THE OTHER 2

OPERATING COMPANIES FOR WINTER RELIABILITY? 3

A. As noted earlier, each retail operating company is responsible for determining the 4

resource additions appropriate for its own service territory that will enable it to meet the 5

needs of its customers in a reliable and cost-effective manner. Interactions with the 6

affiliated companies through mechanisms such as coordinated planning and operation can 7

and do provide benefits and cost savings (including the ability to take advantage of 8

temporary surplus capacity on the system), but they do not alter this fundamental duty 9

and responsibility. Moreover, much of the capacity that gives rise to the higher reserve 10

levels at the other retail affiliates comprises older fossil steam resources. It is no surprise 11

that such resources across the country are under significant cost pressure that threatens 12

their continued operation, for reasons including the ongoing cost of environmental 13

compliance, forecasted low gas prices, and modest load growth. To that end, Georgia 14

Power recently proposed the retirement of Plant Hammond Units 1-4 and Plant McIntosh 15

Unit 1 (totaling approximately 980 MW), and specifically noted economic challenges 16

associated with the continued operation of Plant Bowen Units 1-2 (totaling approximately 17

1500 MW). Under the Order Adopting Stipulation As Amended issued by the Georgia 18

Public Service Commission dated July 29, 2019, the Hammond and McIntosh units were 19

officially retired and capital spending limits were established for Bowen Units 1-2 for the 20

next three years. 21

22

PUBLIC VERSION

14 | P a g e

I would emphasize that Alabama Power is not suggesting, and does not know, 1

what Georgia Power’s ultimate plans may be for the Bowen units. My point is that these 2

are Georgia Power resources and as the owner it controls decisions impacting their future 3

operation (subject, of course, to requisite regulatory approvals under state law). The 4

same would be true for Mississippi Power Company and the resources that it owns. 5

Alternatively, these companies could seek to make wholesale sales predicated on their 6

owned capacity. In either case, the effect would be a reduction in the level of available 7

capacity reserves on the system. Accordingly, Alabama Power cannot and should not 8

count on the sustained availability of capacity owned by its retail affiliates for use in 9

serving the requirements of Alabama customers, particularly given the Company’s 10

reliability obligations as a regulated public utility under Alabama law. 11

Q. GIVEN THE RESULTS OF ALABAMA POWER’S IRP PROCESS AND OTHER 12

RELEVANT CONSIDERATIONS, HOW MUCH CAPACITY DOES THE 13

COMPANY NEED TO SECURE FOR LONG-TERM RELIABILITY 14

PURPOSES? 15

A. The IRP results shown for Alabama Power and for the system, coupled with other factors 16

impacting reliable long-term supply, demonstrate a need for the Company to add 17

approximately 2400 MW of additional resources by the 2023-2024 timeframe. This 18

advancement of the resource additions otherwise indicated by the coordinated system 19

plan across the 2023-2028 timeframe will mitigate the described risks and satisfy the 20

Company’s statutory duty to make reasonable enlargements of its system to meet the 21

demand of those customers for whom it holds a duty to serve. The portfolio of resource 22

PUBLIC VERSION

15 | P a g e

additions proposed for certification, as described in more detail in the last part of my 1

testimony, represent a reliable and cost-effective means of satisfying that need. 2

II. Identification of Potential Resource Opportunities 3

Q. HOW DID ALABAMA POWER GO ABOUT IDENTIFYING RESOURCE 4

OPTIONS AND OPPORTUNITIES THAT MIGHT PROVE TO BE COST-5

EFFECTIVE MEANS OF MEETING ITS RELIABITY NEED? 6

A. The Company’s overarching goal in this undertaking was to consider any resource 7

opportunities that could be appropriate to meet this capacity need, and to then subject 8

those potential options to a rigorous and consistent evaluation. The array of options 9

included the turnkey delivery of a new facility, numerous capacity offerings from the 10

wholesale market, and certain other proposals that evolved from a prior solicitation of 11

renewable energy projects. 12

Q. DESCRIBE THE DEVELOPMENT OF THE TURNKEY PROJECT. 13

A. Building and owning needed capacity resources is a traditional option that is almost 14

always available to a public utility. In this instance, that option took the form of a 15

turnkey combined cycle project at Plant Barry, which is described more fully in Mr. 16

Bush’s testimony. 17

Q. HOW DID ALABAMA POWER OBTAIN LONG-TERM CAPACITY 18

OFFERINGS FROM THE WHOLESALE MARKETS? 19

A. In order to determine the terms and conditions of available opportunities in the wholesale 20

market, the Company publicized and issued a capacity Request for Proposals (“Capacity 21

RFP”). A copy of that RFP is appended to my testimony as Exhibit JBK-2. 22

PUBLIC VERSION

16 | P a g e

Q. WAS THE CAPACITY RFP CONDUCTED UNDER YOUR DIRECTION AND 1

SUPERVISION? 2

A. Yes. 3

Q. HAS ALABAMA POWER RECENTLY CONDUCTED ANOTHER 4

SOLICITATION THAT FOLLOWED A SIMILAR STRUCTURE? 5

A. Yes. In accordance with the requirements of the Commission’s order in Docket No. 6

32383, a Renewable RFP was conducted by Forecasting and Resource Planning in 2018 7

to help identify potentially viable renewable resources that might be candidates for 8

certification pursuant to that order. 9

Q. BRIEFLY DESCRIBE THE CAPACITY RFP. 10

A. On September 21, 2018, the Company issued the Capacity RFP, soliciting proposals for 11

capacity resources either in the form of a power purchase agreement (“PPA”) or an 12

agreement for the acquisition of new-build or existing facilities. The Company expressed 13

a willingness to consider any type of resource that would provide reliable, dispatchable, 14

cost-effective capacity and energy to meet the needs of its customers. Commencement of 15

service would be in the 2019-2023 timeframe, with the amount depending upon the cost 16

competitiveness of the respective offers as well as other options available to the 17

Company. Notice of the RFP was publicized through BusinessWire, a press release 18

distribution service that reaches online, print, broadcast and radio media outlets, reporters 19

and wire services. In addition, a dedicated website was established for the Capacity RFP. 20

Q. WHAT WAS THE LEVEL OF RESPONSE FROM WHOLESALE MARKET 21

PARTICIPANTS?22

PUBLIC VERSION

17 | P a g e

A. Interested bidders submitted 19 proposals that totaled approximately 5,000 MW of 1

capacity (excluding the effect of multiple offerings from the same resource). The 2

electronic bids were opened on November 13, 2018, in the presence of an independent 3

accounting firm and a member of the Commission staff, with an electronic copy of each 4

proposal being retained for future reference by the accounting firm. 5

Q. WHAT WERE THE MAJOR STEPS IN THE CAPACITY RFP PROCESS 6

AFTER THE PROPOSALS WERE RECEIVED?7

A. In general terms, the process consisted of the following steps. For the most part, these 8

are set forth in chronological order, but some overlap may necessarily have occurred. 9

• Assessment of bids to confirm material compliance with the terms of the Capacity 10 RFP 11

12 • Preliminary evaluation on the basis of production costs and other factors 13

14 • Initial due diligence related to proposals to acquire existing facilities 15

16 • A more detailed evaluation to derive a “Competitive Tier” of proposals 17

18 • Initial meetings with each Competitive Tier bidder, encouraging proposal and pricing 19

updates 20 21

• Receipt of updated bid proposals, with electronic copies transmitted to the 22

independent accounting firm for retention 23

24 • Detailed due diligence related to proposals to acquire existing facilities 25

26 • Further analysis of the updated bid proposals, including preliminary transmission 27

costs and impacts, to determine an initial “Shortlist” 28

29 • One-on-one negotiations for projects on the Shortlist, with encouragements for 30

proposal and pricing updates 31

32

• Further analysis to reflect updated information (e.g., bidder proposal refinements, due 33

diligence information, transmission impacts), along with associated contract 34

negotiations 35

PUBLIC VERSION

18 | P a g e

Q. WERE THESE PROPOSALS EVALUATED IN A COMPARABLE MANNER? 1

A. Yes. The economic evaluations used throughout this process assessed the costs and 2

benefits associated with the various competing proposals in a comprehensive and non-3

discriminatory manner. To that end, the Reliability and Resource Procurement group at 4

SCS headed up by Mr. Looney conducted the economic evaluations for the proposals 5

originating from bids in the Capacity RFP as well as the turnkey proposal. The 6

evaluation of proposals for solar photovoltaic facilities paired with battery energy storage 7

systems (“Solar/BESS”) was performed by Forecasting and Resource Planning consistent 8

with the Company’s prior evaluations of solar and other renewable resources. 9

Q. WHY DID YOU RETAIN EVALUATION RESPONSIBILITY FOR THE 10

SOLAR/BESS PROJECTS? 11

A: Given that these proposals originated from the Renewable RFP, Forecasting and 12

Resource Planning had already begun to analyze them and therefore retained evaluation 13

responsibility for the Solar/BESS projects to facilitate ongoing negotiations and to 14

achieve an outcome that best satisfied Alabama Power’s indicated needs. 15

Q: HOW WERE THE SOLAR/BESS PROJECTS EVALUATED? 16

A: Forecasting and Resource Planning utilized an approach comparable to that employed by 17

Mr. Looney’s group and considered the same cost components and resource benefits. 18

Q. EXPLAIN HOW THE SOLAR/BESS PROJECTS EVOLVED. 19

A. I mentioned previously that the Company conducted a Renewable RFP in 2018 in an 20

effort to identify potentially viable renewable resources that might be candidates for 21

certification pursuant to the Commission’s order in Docket No. 32382. As discussions 22

were ongoing in connection with some of those renewable projects, the Company 23

PUBLIC VERSION

19 | P a g e

received proposals for stand-alone battery storage in response to the Capacity RFP. 1

Although the stand-alone battery storage projects were not economically viable options, 2

the Company concluded that a pairing of such storage projects with renewable (solar) 3

projects emanating from the Renewable RFP might together comprise cost-effective 4

capacity resources. That idea led to the submission of various Solar/BESS proposals that, 5

as discussed below, proved to be economically attractive when modeled along with 6

existing system resources. 7

III. Portfolio of Resources Proposed for Certification 8

Q. DESCRIBE THE PORTFOLIO OF RESOURCES THAT WERE SELECTED 9

FOR CERTIFICATION BY THE COMPANY, ON THE BASIS OF COST-10

EFFECTIVENESS AND RELIABILTY, TO MEET THE CAPACITY NEED 11

IDENTIFIED THROUGH THE 2019 IRP PROCESS. 12

A. As reflected in the Petition for a Certificate of Convenience and Necessity, the resource 13

portfolio proposed by the Company to meet the identified capacity need is as follows: 14

• Five (5) Solar/BESS project PPAs, with a cumulative winter capacity equivalence of 15 340 MW (68 MW each) 16

17 • Barry Unit 8 Combined Cycle Project, with an ultimate winter capacity rating of 743 18

MW 19 20

• Hog Bayou PPA, with a winter capacity rating of 238 MW 21 22

• Acquisition of Central Alabama Generating Station, with a winter capacity rating of 23 915 MW 24

25 These supply resources will add an additional 2236 MW to the Company’s winter 26

capacity. While largely resolving the pressing reliability need in the winter season, this 27

total falls short of the indicated need for approximately 2400 MW by the 2023-2024 28

PUBLIC VERSION

20 | P a g e

timeframe. The Company plans to address that difference through the pursuit of 1

approximately 200 MW of new demand-side management programs and distributed 2

energy resources that will be reflected in the next iteration of the IRP. 3

Q. HOW DID THE COMPANY DETERMINE THE SUPPLY-SIDE RESOURCES 4

SHOWN ABOVE TO BE THE MOST RELIABLE AND COST-EFFECTIVE 5

PORTFOLIO OPTIONS? 6

A. As discussed more fully in Mr. Looney’s testimony, the detailed economic evaluation of 7

the expected costs and benefits associated with the various proposals yielded a rank order 8

indicative of their relative economic merit. In addition, and as he explains, a portfolio 9

analysis was necessary to capture the potential for transmission interaction (and hence 10

cost impacts) among the multiple proposals required to satisfy the need. I also directed 11

Mr. Looney to examine the proposals under scenarios representing alternative fuel cost 12

and carbon cost futures. The results of the alternative scenarios produced the portfolio 13

reflected in the Company’s petition. Appropriate regard was also given to the total 14

amount of capacity proposed in the portfolio, as compared to the amount of need 15

identified in the 2019 IRP. 16

Q. DESCRIBE EACH OF THE SUPPLY-SIDE RESOURCES IN THE PROPOSED 17

PORTFOLIO. 18

A. The capacity associated with Solar/BESS projects is reflected in five PPAs with special 19

purpose entities owned by three different developers: three projects with NextEra (Dallas 20

County Solar, LLC, Dothan Solar, LLC and Talladega Solar, LLC), one project with 21

Origis (AL Solar C, LLC), and one project with Southern Current (Anniston Solar, LLC). 22

The PPAs are all structured the same, providing for a nominal 80 MW solar facility plus 23

PUBLIC VERSION

21 | P a g e

a nominal 80 MW BESS. Each BESS must be able to discharge 80 MW for two hours 1

(for a total amount of stored energy of 160 MWh) so as to meet critical system peak 2

demands. Although the BESS component of the contracts provides capacity to the 3

Company, payments to the sellers are all energy-based. Alabama Power has the right to 4

direct the charging and discharging of the BESS during an eight-month period each year, 5

including both the winter and summer peak seasons. The seller is subject to liquidated 6

damages under certain specified circumstances, including failure to meet contractual 7

guarantees relating to actual production from the solar facility and the capacity of the 8

BESS. These PPAs are appended to my testimony as Exhibit JBK-3, Exhibit JBK-4, 9

Exhibit JBK-5, Exhibit JBK-6 and Exhibit JBK-7. 10

Barry Unit 8 is a combined cycle facility with initial capacity ratings of 726 MW 11

(with a scheduled uprate to 743 MW) in the winter and 653 MW (with a scheduled uprate 12

to 685 MW) in the summer. It is being constructed pursuant to a turnkey contract with 13

Mitsubishi Hitachi Power Systems Americas, Inc. and Black & Veatch Construction, 14

Inc., both of whom are responsible for the engineering, equipment procurement and 15

construction activities specified in the contract. The Company (through its agent, SCS) 16

will maintain oversight to ensure contract compliance and is also responsible for certain 17

site-related and interconnection work. A full description of the Barry Unit 8 project is set 18

forth in Mr. Bush’s testimony, which includes relevant portions of the turnkey contract as 19

an exhibit. 20

The proposed PPA between Alabama Power and Mobile Energy, LLC (an 21

affiliate of the LS Power Development, LLC) (“Mobile”), appended to my testimony as 22

Exhibit JBK-8, provides the Company rights to the entire capability of the Hog Bayou 23

PUBLIC VERSION

22 | P a g e

Energy Center located in Mobile County, Alabama, for a total term of approximately 1

nineteen (19) years. The Hog Bayou Energy Center is a combined cycle, natural-gas 2

fired facility with a summer rating of 222 MW and a winter rating of 238 MW. In order 3

to address certain near-term reliability needs, the PPA calls for an early start period 4

beginning in 2020 through November 2023, followed by a fifteen (15) year term 5

beginning in December 2023. Along with monthly capacity payments, Alabama Power is 6

responsible for an energy payment that includes a charge for each unit start, plus a charge 7

for variable O&M expenses and a fuel adjustment based on a guaranteed heat rate. (The 8

PPA also includes a minimum availability rate.) As this is a “tolling” PPA, the Company 9

is handling the fuel-related arrangements (commodity and transportation). Extended 10

periods of unavailability below a specified level constitutes an event of default by 11

Mobile, in which case Alabama Power would be entitled to termination payments. 12

The final supply-side component of the portfolio is the acquisition of the Central 13

Alabama Generating Station (“Central Alabama”) located near Billingsley, Alabama. 14

Central Alabama is a combined cycle facility constructed in 2003, with a winter capacity 15

rating of 915 MW and a summer capacity rating of 890 MW. The facility is owned by 16

Tenaska Alabama II Partners, L.P., a Delaware limited partnership in which a Tenaska 17

subsidiary is the managing general partner and majority owner. Until May 2023, Central 18

Alabama is subject to a PPA with under 19

which it is entitled to the capacity of the facility and the associated energy. Upon the 20

closing of a Purchase and Sale Agreement (“PSA”), Alabama Power will become the 21

owner of Central Alabama. At that point, the facility is expected to have a remaining 22

useful life of approximately 23 years. The terms and provisions of the above-described 23

PUBLIC VERSION

23 | P a g e

PPA with will remain in place until it expires, with Alabama Power entitled to 1

receive the associated revenues. The Company will thereafter have the same rights and 2

responsibilities associated with Central Alabama as with any other generating facility 3

owned by the Company. The PSA is subject to a number of conditions, specifically 4

including receipt of requisite regulatory approvals. The PSA, in its agreed upon form and 5

with relevant ancillary transaction documents, is appended to my testimony as Exhibit 6

JBK-9. The PSA is not yet signed by the parties, but execution is forthcoming. At an 7

appropriate time, the Company will supplement this exhibit to reflect finalization. 8

Q. DESCRIBE THE DEMAND-SIDE MANAGEMENT AND DISTRIBUTED 9

ENERGY RESOURCE PROGRAMS THAT THE COMPANY SEEKS TO 10

PURSUE. 11

A. As set forth in the petition, the Company is requesting authorization to pursue an increase 12

of 200 MW in demand-side management and distributed energy resource programs. At 13

this time, the Company does not know the mix of programs it will seek to implement; 14

however, examples of potential demand-side management programs include: 15

• A smart thermostat program, coupled with the deployment of high efficiency heat 16 pumps; 17

18 • An “Orchestrated Energy” program, by which the Company would incent the shifting 19

of load from higher cost periods to lower cost periods; and 20 21

• Expansion of existing standby generation, non-firm, load shifting and critical peak 22 pricing programs. 23

24 Q. WHAT DISTRIBUTED ENERGY RESOURCE PROGRAMS IS THE COMPANY 25

CONTEMPLATING? 26

PUBLIC VERSION

24 | P a g e

A. Here too, the Company’s program evaluation remains ongoing. The Company envisions, 1

however, the potential for deployments both at a utility scale level as well as smaller 2

scale facilities (e.g., less than 1 MW), all at customer locations. 3

Q. DOESN’T THE COMPANY HAVE AN EXISTING CERTIFICATE FOR SUCH 4

PROJECTS? 5

A. The Commission did authorize a blanket certificate for renewable generation and 6

environmentally specialized resources in 2015 in Docket No. 32382. By its terms, that 7

certificate expires in 2021, which is during the triennial cycle of the Company’s 8

integrated resource plan. The Company may separately elect to pursue renewal of that 9

certificate, but in connection with the current need-based petition, the Company seeks to 10

obtain appropriate authorization now so that it can proceed forward with program 11

development. 12

Q. HOW DOES THE COMPANY PROPOSE TO IMPLEMENT ITS DEMAND-SIDE 13

MANAGEMENT AND DISTRIBUTED ENERGY RESOURCE PROGRAMS? 14

A. Similar to the projects under the renewable generation certificate, the Company would 15

submit the demand-side management and distributed energy resource programs for 16

Commission approval on a project-by-project basis. For each project, Alabama Power’s 17

evaluative criteria would be that the project results in positive benefit for all customers 18

over the term of the project relative to the applicable benchmark plan, taking into account 19

the costs and revenue impacts of the project and the expected value corresponding to the 20

avoided capacity addition, along with other positive benefits that may accrue through 21

load growth, load retention or other relevant considerations associated with the particular 22

project. 23

PUBLIC VERSION

25 | P a g e

Q. DO YOU HAVE ANY CONCLUDING REMARKS RELATED TO THE 1

COMPANY’S PETITION AND ASSOCIATED TESTIMONY? 2

A. As demonstrated in my testimony and that of the other witnesses, the Company’s petition 3

is fully supported in all respects. There is the clear showing of a need for additional 4

capacity resources that will enable Alabama Power to continue to fulfill its duty to 5

provide reliable service to its customers. The testimony further shows that the Company 6

has selected a portfolio that constitutes a reasonable and cost-effective means of 7

satisfying that need. 8

Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 9

A. Yes.10

PUBLIC VERSION

PUBLIC VERSION

Direct Testimony of John B. Kelley

Exhibit JBK-1

PUBLIC VERSION

PUBLIC VERSION

1

Alabama Power Company 2019 IRP Summary ReportPublic Version2019 Integrated Resource Plan Summary Report

Public Version

PUBLIC VERSION

I

Alabama Power Company 2019 IRP Summary ReportPublic Version

TABLE OF CONTENTS

EXECUTIVE SUMMARY ....................................................................................................................................... 1

I. INTRODUCTION AND OVERVIEW ........................................................................................................... 5

II. ENVIRONMENTAL STATUTES AND REGULATIONS ............................................................................. 8

II.A. General ............................................................................................................................................................... 8

II.B. Air Quality .............................................................................................................................................................9

II.C. Water Quality .................................................................................................................................................... 12

II.D. Coal Combustion Residuals .......................................................................................................................... 13

II.E. Climate Issues .................................................................................................................................................... 14

III. INTEGRATED RESOURCE PLAN .............................................................................................................. 15

III.A. Process Overview ............................................................................................................................................. 15

III.B. Load Forecast .................................................................................................................................................... 19

III.C. Fuel Forecast ..................................................................................................................................................... 22

III.D. Reserve Margin .................................................................................................................................................23

III.E. Emerging Resiliency Needs .......................................................................................................................... 29

III.F. Development of Indicative Resource Additions .................................................................................. 29

IV. CONCLUSION ............................................................................................................................................. 34

FIGURES

Figure ES-1 Summer and Winter Target Planning Reserve Margin Comparison..............................3

Figure I-1 Alabama Power Capacity Mix ....................................................................................................6

Figure III-A-1 Alabama Power IRP Process ...................................................................................................... 16

Figure III-B-1 Alabama Power Weather Normalized Historical Peak Demand with Forecast ..... 21

Figure III-D-1 Alabama Power Projected Seasonal Reserve Margins .....................................................27

Figure III-D-2 Alabama Power Projected Winter Capacity Needs ..........................................................27

Figure III-D-3 Alabama Power Projected Summer Capacity Needs ...................................................... 28

Figure III-F-1 Alabama Power Winter Benchmark Plans ............................................................................32

Figure A1-1 Alabama Power Company Existing Supply-Side Resources ........................................A1-1

PUBLIC VERSION

II


Figure A2-1 Winter – Integrated Resource Plan 2019 Projections of

Active Demand-Side Options (DSOs) 2019-2038 ..........................................................A2-3

Figure A2-1 Summer – Integrated Resource Plan 2019 Projections of

Active Demand-Side Options (DSOs) 2019-2038 ..........................................................A2-4

Figure A2-2 Winter – Integrated Resource Plan 2019 Projections of

Passive Demand-Side Options (DSOs) 2019-2038 ........................................................ A2-7

Figure A2-2 Summer – Integrated Resource Plan 2019 Projections of

Passive Demand-Side Options (DSOs) 2019-2038 ....................................................... A2-8

APPENDICES

Appendix 1: Alabama Power Company Existing Supply-Side Resources ......................................A1-1

Appendix 2: Alabama Power Company Demand-Side Management Programs .......................A2-1

Appendix 3: Alabama Power Company Procurement of Renewable Resources .......................A3-1

PUBLIC VERSION

1


EXECUTIVE SUMMARY

The 2019 Integrated Resource Plan (“2019 IRP”)1 for Alabama Power Company (“Alabama Power” or

“Company”) is a comprehensive process that serves as the foundation for certain decisions affecting

the Company’s future portfolio of supply-side and demand-side resources.2 The IRP process does not

produce binding determinations concerning new specific resources that the Company will procure

in the future. Rather, it is a management tool that, using the best information currently available,

facilitates the Company’s ability to make future resource decisions that result in reliable and cost-

effective electric service to customers, while accounting for risks and uncertainties inherent in

planning for resources sufficient to meet expected customer demand. The dynamic nature of the

Company’s IRP process thus produces a comprehensive plan of indicative resource additions that

serves as the basis on which the Company can develop and manage its portfolio of supply-side and

demand-side management (“DSM”) resources to provide reliable electric service to its customers.

The IRP is developed on a formal basis every three years and is reviewed with the staff of the

Alabama Public Service Commission (“APSC”). This review keeps the APSC informed as to the timing

of needed resource additions, while also helping to ensure that the process yields results that are

consistent with the Company’s ultimate goals of minimizing rates and providing the desired level

of service reliability. These goals are important because they allow the Company to be competitive

with other energy providers and promote economic development within the State of Alabama.

Alabama Power remains committed to maintaining a diverse supply-side generating portfolio, along

with cost-effective DSM resources that benefit all customers. Resource diversity on the supply side,

which includes nuclear, natural gas, coal, oil, hydroelectric, wind, solar, and biomass resources, provides

significant benefit to customers, as it enables the Company to adapt to changes impacting its energy

supply obligations. In that regard, the Company’s generating fleet is transitioning due to a number of

factors, including the cost of natural gas and the cost impacts of various environmental regulations

1 As noted, the IRP is a comprehensive, data-intensive process that ultimately yields an indicated list of future resource additions designed to meet appropriate reliability requirements in a cost-effective manner. This Summary Report only serves to overview that process and summarize its results; however, for ease of reference this document is sometimes referred to as the “2019 IRP”. 2 Appendix 1 is a detailed list of all supply-side resources owned and controlled by Alabama Power. Appendix 2 summarizes the Company’s activities related to existing and potential Demand Side Management (“DSM”) programs.

PUBLIC VERSION

2


by the U.S. Environmental Protection Agency (“EPA”). A recent example of an environmentally-driven

change is the retirement of Gorgas Units 8-10 due to the compliance requirements of EPA’s coal

combustion residuals rule (Disposal of Coal Combustion Residuals from Electric Utilities, or “CCR

Rule”). Ongoing uncertainties also persist in connection with EPA’s Effluent Limitation Guidelines rule

addressing wastewater limits for steam electric power plants, as well as initiatives at the federal

level to regulate or tax carbon dioxide (“CO2”) emissions. The cost and operating implications for

the Company’s supply resources related to these and other considerations remain factors in the

Company’s planning scenarios related to the 2019 IRP.

As reflected in the 2019 IRP, Alabama Power’s planning process now separately considers the winter

and the summer seasons, thereby ensuring sufficient reserve capacity during different times of

the year, as compared to a focus solely on summer reliability. Historically, the Company’s capacity

planning decisions have been driven by summer peak loads and a corresponding summer-focused

Target Reserve Margin. These planning techniques have proven to be successful in supporting

reliability, while cost-effectively meeting the needs of customers. However, operational experience

over the last several years, and in particular a winter peak demand for the Alabama Power system,

demonstrates a significant transition in reliability risk from the summer-only season to predominantly

the winter season. As a result, Alabama Power is modifying its summer-based capacity planning

approach to specifically address reliability on a seasonal basis. Seasonal planning provides greater

visibility into capacity needs in both summer and winter, rather than limiting reliability decisions to

a single season.

In support of the transition to seasonal planning, the 2019 IRP reflects the results of the most recent

Reserve Margin Study for the Southern Company System (“System”). The Reserve Margin Study

provides a detailed reliability analysis that yields Target Reserve Margins for the System. Based

upon the Reserve Margin Study, the Company is utilizing seasonal Target Reserve Margins for all

future planning purposes. For long-term planning starting in 2022 and beyond, the Company’s plan

maintains a System Target Reserve Margin of 16.25 percent for summer periods (“Summer Target

Reserve Margin”). For winter periods, the Company is adopting a long-term planning Target Reserve

Margin for the System of 26 percent (“Winter Target Reserve Margin”). Consistent with past practice,

the Company also evaluated the short term (2019-2021) Target Reserve Margin and for planning

PUBLIC VERSION

3


purposes is adopting a 15.75 percent target for summer and a 25.5 percent target for winter. Due to

the benefits of load diversity, coordinated planning and operations, and the ability to share resources,

the Southern Company retail operating companies can together achieve these System targets by

each utilizing diversified reserve margins that are lower than the Target Reserve Margins for the

System. Thus, the diversified Summer Target Reserve Margins for Alabama Power are 14.89 percent

over the long-term and 14.39 percent over the short-term. Likewise, Alabama Power’s diversified

Winter Target Reserve Margins are 25.25 percent over the long-term and 24.75 percent over the

short-term. These diversified values are subject to change in response to changes in System load

diversity. Figure ES-1 compares the previous planning reserve margin targets to those predicated on

the updated Reserve Margin Study.

FIGURE ES-1: Summer and Winter Target Planning Reserve Margin Comparison

Based on these Target Reserve Margins, and taking into account the Company’s load forecast and

other considerations reflected in the 2019 IRP, Alabama Power projects a resource deficit as of

,

longer-term resources need to be procured to address the Company’s deficit in winter 2024 and

3 The Southern Pool is governed by the terms of the Southern Company System Intercompany Interchange Contract, which is a rate schedule on file with the Federal Energy Regulatory Commission (“FERC”). Well-recognized benefits of pooling include lower production costs for the participants (as opposed to stand-alone operation), lower reserve margins due to load diversity, and the ability to take advantage of economies of scale by sharing temporary surplus and deficit capacity.

Previous Updated Reserve Reserve Margin Study Margin Study System Long-Term Target Planning Reserve Margin (Summer) 16.25% 16.25% System Short-Term Target Planning Reserve Margin (Summer) 14.75% 15.75% Diversified Long-Term Target Planning Reserve Margin (Summer) 14.74% 14.89% Diversified Short-Term Target Planning Reserve Margin (Summer) 13.26% 14.39% System Long-Term Target Planning Reserve Margin (Winter) - 26.00% System Short-Term Target Planning Reserve Margin (Winter) - 25.50% Diversified Long-Term Target Planning Reserve Margin (Winter) - 25.25% Diversified Short-Term Target Planning Reserve Margin (Winter) - 24.75%

PUBLIC VERSION

4


beyond. To meet this need, the Company will continue to employ the principles discussed earlier

to identify an economic set of resource options that are projected to provide the most benefit to

customers at the lowest practicable cost. Upon identification of these resources, the Company will

seek authorization from the APSC for procurement or development rights, as applicable.

PUBLIC VERSION

5


I. INTRODUCTION AND OVERVIEW

Alabama Power is an investor-owned electric utility, organized and existing under the laws of the

State of Alabama, and is a subsidiary of the Southern Company. In addition to Alabama Power,

the Southern Company is the parent of Georgia Power Company, Mississippi Power Company, and

Southern Power Company (collectively, the “Operating Companies”), as well as certain service and

special-purpose subsidiaries. Alabama Power is primarily engaged in generating, transmitting and

distributing electricity to the public in a large section of Alabama. The Company’s retail rates and

services are regulated by the APSC under the provisions of Title 37 of the Code of Alabama.

The Company has approximately 1.48 million customers, of which approximately 86 percent (1.27

million) are residential; 13.5 percent (200,000) are commercial; and 0.5 percent (6,900) are industrial

and other. Alabama Power has approximately 1.57 million transmission and distribution poles, and

approximately 85,000 miles of wire. The Company strives to maintain cost-effective and reliable

service to its customers. For the years 2017-2018, the Company had a service reliability of 99.98 percent.

As noted earlier, Alabama Power has a diverse mix of supply-side (both owned and contracted) and

demand-side resources, including hydroelectric, natural gas, nuclear, coal, oil, renewable projects,4

combined heat and power, and DSM programs.

As of April 2019, Alabama Power’s supply-side capacity resources had a winter generating capability

of approximately 12,600 MW and a summer generating capability of approximately 12,500 MW.

These resources, along with active DSM programs having a capacity value of approximately 1,200

MW, represent a diverse mix of capacity totaling nearly 14,000 MW, as demonstrated in the following

chart. A more detailed breakdown of the Company’s generating and demand side resources is

presented in Appendices 1 and 2.

4 As applicable to all references of renewable projects in this 2019 IRP, the Company has rights to the environmental attributes, including the renewable energy certificates (“RECs”), associated with the energy from these projects. Alabama Power can choose to retire some, or all, of these environmental attributes on behalf of its retail electric customers, or it can sell the environmental attributes, either bundled with energy or separately, to third parties. Included in Appendix 1 is a listing of the Company’s contracted or owned renewable projects. Appendix 3 provides an overview of the Company’s efforts directed to the procurement of renewable resources.

PUBLIC VERSION

6


Figure I-1: Alabama Power Capacity Mix

This document summarizes the results of Alabama Power’s 2019 IRP and describes the process used

in its development. As noted at the outset, the IRP serves as the foundation for certain decisions

affecting the Company’s portfolio of generating resources, facilitating the Company’s ability to

provide reliable and cost-effective electric service to its customers. At the most basic level, the IRP

yields an indicative annual schedule of integrated supply-side and demand-side resource additions

to accomplish the aforementioned objectives, consistent with the Company’s duties and obligations

to the public as a regulated public utility. The Company’s IRP is performed through a coordinated

process utilized across the Southern Company retail operating companies, with the assistance of their

agent, Southern Company Services, Inc. (“SCS”). The process used by Alabama Power to develop the

IRP comports with the provisions of the Public Utility Regulatory Policies Act of 1978, as amended,

which contemplates the use of appropriate integrated resource planning by electric utilities.

Together with the other Operating Companies, Alabama Power participates in the Southern Pool,

which provides for coordinated system operations and centralized unit commitment and joint

2019

13% 11%

28%

32%

12%

4%

Gas Coal Nuclear Other Hydro DSO

PUBLIC VERSION

7


dispatch of the Operating Companies’ respective generating units.5 In order to take advantage of

economies of scale, the retail Operating Companies engage in the coordinated planning of their

respective resource additions; however, each such operating company retains final decision-making

authority with regard to any resource additions that it may require, consistent with its respective

duty of service as provided by law.

The System is represented on the Southeastern Electric Reliability Council (“SERC”), which serves

to coordinate operations and other measures to maintain a high level of reliability for the electric

system in the Southeastern United States. Likewise, Alabama Power and the other retail Operating

Companies, along with other transmission owners in the region, are sponsors of the Southeastern

Regional Transmission Planning process, which provides an open, coordinated, and transparent

transmission planning process for much of the Southeast in accordance with the requirements of

FERC.

In order to anticipate future energy and demand requirements of the customers it serves, Alabama

Power develops a load forecast that comprises a 20-year projection of the expected growth in

customer requirements. Using the best information reasonably available, the Company then develops

an IRP that reflects the indicated optimal mix of supply-side and demand-side resources to meet

this projected customer peak demand in a reliable and cost-effective manner. Alabama Power has

traditionally been considered summer peaking, meaning its annual peak demand falls during the

summer months; however, its customer demands have been growing in the winter months. Indeed,

in recent years, Alabama Power’s weather-normalized winter peak demand has exceeded its summer

peak demand, and its most recent load forecast projects a predominant winter peak demand. The

Company’s load forecast is discussed further in Section III.B.

5 On January 1, 2019, Gulf Power Company was sold to NextEra Resources and is no longer a subsidiary of the Southern Company. During a transition period, Gulf Power will continue to participate in the Southern Pool, but is no longer a part of coordinated planning by the remaining retail operating companies.

PUBLIC VERSION

8


II. ENVIRONMENTAL STATUTES AND REGULATIONS6

II.A. General

The Company’s operations are subject to extensive regulation by state and federal environmental

agencies under a variety of statutes and regulations that impact air, water, and land resources. Applicable

statutes include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response,

Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances

Control Act; the Emergency Planning and Community Right-to-Know Act; the Endangered Species Act;

the Migratory Bird Treaty Act; the Bald and Golden Eagle Protection Act; and related federal and state

regulations. Compliance with these and other environmental requirements involves significant capital and

operating costs. Through 2018, the Company had invested approximately $5.4 billion in environmental

capital retrofit projects to comply with these requirements. The Company currently expects that capital

expenditures to comply with environmental statutes and regulations will total approximately $635

million from 2019 through 2023. These estimates do not include any potential compliance costs associated

with pending regulation of CO2 emissions from fossil fuel-fired electric generating units. The Company

also anticipates costs associated with closure in place and groundwater monitoring of ash ponds in

accordance with the CCR Rule, which are not reflected in the capital expenditures above, as these costs

are associated with the Company’s asset retirement obligation (“ARO”) liabilities.

The Company’s ultimate environmental compliance strategy, including potential unit retirement and

replacement decisions, and future environmental capital expenditures will be affected by the final

requirements of new or revised environmental regulations and the outcome of any associated legal

challenges; the cost, availability, and existing inventory of emissions allowances; and the Company’s fuel

mix. To date, the Company’s compliance strategy in response to federal environmental requirements has

resulted in a reduction of more than 2,100 MW of coal-fired capacity, due either to fuel switching, the

retirement of units, or the placing of units on inactive reserve. Compliance costs may arise from existing

unit retirements, installation of additional environmental controls, upgrades to the transmission system,

closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units.

6 The information in this section is drawn from the combined annual report on Form 10-K of The Southern Company and the Operating Companies for the year ended December 31, 2018, as filed with the Securities and Exchange Commission. Any material difference between the information contained therein and this section is unintended and the annual report should be referenced as the controlling discussion.

PUBLIC VERSION

9


Compliance with any new federal or state legislation or regulations relating to air, water, and land

resources or other environmental and health concerns could significantly affect the Company.

Although new or revised environmental legislation or regulations could affect many areas of the

Company’s operations, the full impact of any such changes cannot be known with certainty until

the applicable legislation or regulation is finalized, legal challenges are resolved, and any necessary

rules are implemented at the state level. In any case, such governmental mandates could result

in significant additional capital expenditures and compliance costs that could affect future unit

retirement and replacement decisions. Many of the Company’s commercial and industrial customers

may also be affected by such future environmental requirements, which for some may have the

potential to ultimately affect their demand for electricity.

II.B. Air Quality

Compliance with the Clean Air Act and resulting regulations has been and will continue to be a

significant focus for the Company. Additional controls to further reduce air emissions, maintain

compliance with existing regulations, and meet new requirements may become necessary in the

future, depending on further actions taken by the EPA.

In 2012, the EPA finalized the Mercury and Air Toxics Standards (“MATS”) rule, which imposed stringent

emissions limits for acid gases, mercury, and particulate matter on coal- and oil-fired electric utility

steam generating units (“EGUs”). The compliance deadline set by the final MATS rule was April 16,

2015, with provisions for extensions to April 16, 2016. The implementation strategy for the MATS rule

included emission controls, retirements, and fuel conversions to achieve compliance by the deadlines

applicable to each Company unit. In June 2015, the Supreme Court issued a decision finding that, in

developing the MATS rule, the EPA had failed to properly consider costs in its decision to regulate

hazardous air pollutant (“HAP”) emissions from EGUs. In December 2015, the D.C. Circuit remanded

the MATS rule to the EPA without vacatur to respond to the Supreme Court’s decision. The EPA’s

supplemental finding in response to the Supreme Court’s decision, which was finalized in April 2016,

did not have any impact on the MATS rule compliance requirements or deadlines.

On December 26, 2018, the EPA proposed to revise the Supplemental Cost Finding for MATS. The

EPA proposes to correct what it identifies as flaws in the 2016 cost/benefit analysis it used to

PUBLIC VERSION

10


regulate HAPs from coal- and oil-fired EGUs. The EPA has now determined that the direct benefits

from regulating HAPs from EGUs are grossly outweighed by the costs and consequently, it is not

“appropriate and necessary” to regulate EGU HAP emissions. However, the EPA is not proposing to

rescind MATS, and it reasons that MATS will remain in place based on its interpretation of 2008

D.C. Circuit Court decisions. In a companion action, the EPA is also proposing that remaining risks

associated with EGU HAP emissions are acceptable and therefore, more stringent standards under

MATS are not warranted.

The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone

National Ambient Air Quality Standard (“NAAQS”). In 2015, the EPA adopted a revised eight-hour

ozone NAAQS and in 2017 published its final area designations for Alabama. All areas within the

Company’s service territory have achieved attainment of the 2015 ozone standard.

The EPA regulates fine particulate matter concentrations on an annual and 24-hour average basis.

All areas within the Company’s service territory have achieved attainment with the 1997 and 2006

particulate matter NAAQS, and the EPA has officially redesignated former nonattainment areas

within the service territory as attainment for these standards. In 2012, the EPA issued a final rule

that increases the stringency of the annual fine particulate matter standard. The EPA completed final

designations for the 2012 annual standard for Alabama in March 2015, and no new nonattainment

areas were designated within the Company’s service territory.

Final revisions to the NAAQS for sulfur dioxide (“SO2”), which established a new one-hour standard,

became effective in 2010. In January 2017, the Company submitted modeling showing attainment of

the SO2 standard in the vicinity of its coal-fired generating plants. Based on this modeling analysis,

the EPA did not designate any area in Alabama as nonattainment for this standard. On May 25, 2018,

in its review of the SO2 ambient air quality standard, the EPA proposed to retain the existing level

of the standard.

In February 2014, the EPA proposed to delete from the Alabama State Implementation Plan (“SIP”)

the Alabama opacity rule that the EPA approved in 2008. This action by the EPA, which provides

operational flexibility to affected units, was in response to a 2013 ruling by the U.S. Court of Appeals

PUBLIC VERSION

11


for the Eleventh Circuit that vacated an earlier attempt by the EPA to rescind its 2008 approval. The

EPA’s latest proposal characterizes the proposed deletion as an error correction within the meaning

of the Clean Air Act.

In 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”) to address impacts in downwind

states of SO2 and nitrogen oxide (“NOX”) emissions from fossil fuel-fired electric generating plants.

CSAPR established emissions trading programs and allowance budgets for certain states and allocates

emissions allowances for sources in those states, including Alabama. In 2016, the EPA published a final

CSAPR Update rule, establishing more stringent ozone season NOX emissions budgets for several

states, including Alabama. On December 6, 2018, the EPA finalized the “CSAPR Close-Out” rule

regarding interstate transport requirements for the 2008 ozone standard. The EPA determined that

the 20 states affected by the CSAPR Update rule (including Alabama) have fully met their interstate

transport obligations and that emissions from these states do not contribute significantly to any

downwind state’s ability to meet the 2008 ozone standard. The Company is complying with CSAPR

and operating its units within the emissions allowances allocated to the Company under all CSAPR

allowance programs.

The EPA finalized regional haze regulations in 2005 and 2017. These regulations require states, tribal

governments, and various federal agencies to develop and implement plans to reduce pollutants

that impair visibility and demonstrate reasonable progress toward the goal of restoring natural

visibility conditions in certain areas, including national parks and wilderness areas. In December

2018, the EPA proposed to approve the State of Alabama’s progress report for the first regional haze

planning period. Alabama must also submit to the EPA by July 31, 2021 a revised SIP, demonstrating

continued reasonable progress towards achieving visibility improvement goals. These plans could

require reductions in certain pollutants, such as particulate matter, SO2, and NOX, which could result

in increased compliance costs. Regional haze regulations also involve the application of Best Available

Retrofit Technology (“BART”) to sources including certain Company generating units. What constitutes

BART has been the subject of litigation and is still an unresolved issue for some units operated by the

Company and thus the ultimate impact from BART requirements is currently unknown.

In 2012, the EPA published proposed revisions to the New Source Performance Standard (“NSPS”) for

PUBLIC VERSION

12


Stationary Combustion Turbines (“CTs”). If finalized as proposed, the revisions would apply the NSPS

to all new, reconstructed, and modified CTs (including CTs at combined cycle units) during all periods

of operation, including startup and shutdown, and alter the criteria for determining when an existing

CT has been reconstructed.

In June 2015, the EPA published a final rule requiring certain states (including Alabama) to revise or

remove the provisions of their SIPs relating to the regulation of excess emissions at industrial facilities,

including fossil fuel-fired generating facilities, during periods of startup, shut-down, or malfunction

(“SSM”) by no later than November 2016. In ensuing litigation, the EPA filed a motion with the D.C.

Circuit to hold the matter in abeyance while the agency conducts a review. The court granted EPA’s

motion and the agency is reconsidering its SSM policies and guidance.

II.C. Water Quality

In November 2015, the EPA published the final effluent limitations guidelines rule that imposes

stringent technology-based requirements for certain wastestreams from steam electric power plants

(“2015 ELG Rule”). The 2015 ELG Rule requires major changes to wastewater treatment systems at coal-

fired plants, with stringent restrictions affecting the disposition of fly ash transport water (“FATW”),

bottom ash transport water (“BATW”), and flue gas desulfurization (“FGD” or “scrubber”) wastewater.

The new effluent limits will be implemented in National Pollutant Discharge Elimination System

(“NPDES”) permits issued by the Alabama Department of Environmental Management (“ADEM”),

with applicability based on relevant information provided by the facility (as early as November

1, 2018, but not later than December 31, 2023). However, uncertainty surrounds certain portions of

the 2015 ELG Rule, as the EPA is scheduled to issue a new rulemaking by spring of 2020 that could

revise the limitations and/or applicability dates for BATW and FGD wastewater. The impact of any

changes to the 2015 ELG Rule will depend on the content of the new rule and the outcome of any

legal challenges.

Another part of the Clean Water Act (“CWA”) applicable to Alabama Power is Section 316(b), which

requires that “the location, design, construction and capacity of cooling water intake structures

reflect the best technology available [“BTA”] for minimizing adverse environmental impact.” After

a series of rulemakings and court cases extending all the way to the U.S. Supreme Court, a final

PUBLIC VERSION

13


rule was published in the Federal Register in August 2014, establishing impingement mortality and

entrainment requirements for existing power generating facilities and manufacturing and industrial

facilities that are designed to withdraw more than two million gallons of water per day from waters

of the United States and use at least 25 percent of that water exclusively for cooling purposes

(“316(b) Rule”). The new rule became effective in October 2014. Compliance is required “as soon

as practicable” according to the schedule of requirements set by the permitting authority. NPDES

permits issued after July 14, 2018 must include conditions to implement and ensure compliance

with the standards and protective measures required by the rule. With the recent issuance of the

Greene County NPDES permit renewal, ADEM has required any remaining Section 316(b) studies to

be submitted in the next 5-year permit cycle. Alabama Power has begun conducting these studies

and currently anticipates that changes to Cooling Water Intake Structures (“CWIS”) may include fish-

friendly CWIS screens with fish return systems and the addition of minor monitoring equipment at

certain plants. However, the ultimate impact of the 316(b) Rule will depend on the outcome of these

plant-specific studies and any additional protective measures required by ADEM to be incorporated

into each plant’s NPDES permit renewal in the next permit cycle, based on site-specific factors.

In June 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the

regulatory definition of Waters of the United States (“WOTUS”) for all CWA programs. The final rule

significantly expanded the scope of federal jurisdiction under the CWA and could have a material

adverse impact on economic development projects, which could affect growth in customer demand.

In addition, this rule could significantly increase permitting and regulatory requirements and costs

associated with the siting of new facilities and the installation, expansion, and maintenance of

transmission and distribution lines. Moreover, in 2019, the EPA and the Army Corps of Engineers are

anticipated to publish a final rule to replace the WOTUS definition established in 2015. The impact of

any changes to the 2015 WOTUS rule will depend on the content of this final rule and the outcome

of any challenges.

II.D. Coal Combustion Residuals

In 2015, the EPA finalized the CCR Rule, which established non-hazardous solid waste regulations

for the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments (ash

ponds) at active generating power plants. Among other things, the CCR Rule requires CCR units

PUBLIC VERSION

14


to be evaluated against a set of performance criteria. The State of Alabama has also finalized its

own regulations regarding the handling of CCR. In April 2019, Alabama Power initiated closure of its

unlined CCR impoundments and ash ponds.

II.E. Climate Issues

On July 8, 2019, the EPA published the final version of the Affordable Clean Energy (“ACE”) Rule, which

is to replace a regulation enacted in 2015 (the “Clean Power Plan” or “CPP”) that would limit CO2

emissions from existing fossil fuel-fired EGUs. The CPP has been stayed by the U.S. Supreme Court

since February 2016. The ACE Rule would require states to develop unit-specific CO2 emission rate

standards based on heat-rate efficiency improvements for existing coal-fired steam units. Under the

final rule, combustion turbines, including natural gas combined cycles units, are not affected sources.

Alabama Power owns seven coal-fired steam units to which the ACE Rule is applicable. The ultimate

impact of this rule on Alabama Power is currently unknown and will depend on subsequent state

plan developments and requirements, along with any associated legal challenges.

On December 20, 2018, the EPA published a proposed review of the Standards of Performance for

Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric

Utility Generating Units final rule (“2015 NSPS Rule”). The EPA’s final 2015 NSPS rule set standards of

performance for new, modified, and reconstructed electric utility generating units, which includes

stationary combustion turbines and fossil-fired steam boilers. This proposal reduces the stringency of

the 2015 NSPS Rule by not basing the new and reconstructed fossil-fired steam boiler and integrated

gasification combined cycle (“IGCC”) standards on partial carbon capture and sequestration. The

impact of any changes to this rule will depend on the content of the final rule and the outcome of

any legal challenges.

Separate and apart from these regulations, the prospect remains for federal legislation imposing

a tax on carbon emissions or establishing a national cap and trade carbon emission allowance

system. As with other environmental requirements, any legislative or regulatory action directed to

CO2 emissions could result in significant additional capital expenditures or compliance costs for the

Company, and thus affect future unit retirement and replacement decisions.

PUBLIC VERSION

15


III. INTEGRATED RESOURCE PLAN

III.A. Process Overview

The integrated resource planning process is designed to identify the timing, amount, and types of

resources necessary to serve the long-term energy and demand requirements of Alabama Power’s

customers. Aided by the IRP, the Company is able to develop and implement a resource strategy that

is reasonably expected to provide for cost-effective and reliable service.

The 2019 IRP, which has a 20-year planning horizon, indicates the optimal mix of resources necessary

to meet customers’ future load requirements. Using the best information available at the time of

its development, the IRP provides the basis for estimating potential capital expenditures that may

be required for future generating capacity additions. In the IRP, both supply-side and demand-side

options are evaluated and integrated on a consistent basis using marginal cost analysis. This approach

ensures that both options are identified for potential selection and deployment when such options

represent a viable economic choice.

As shown in Figure III-A-1, integrated resource planning is an iterative process that evaluates existing

and potential resource options in an effort to identify the best combination, in terms of reliability

and expected total cost for serving customers.

PUBLIC VERSION

16


FIGURE III-A-1: Alabama Power IRP Process

PRIORBENCHMARK

PLAN

INTEGRATION

NEWBENCHMARK

PLAN

UPDATE MARGINALCOST PROJECTIONS LOAD FORECAST

UPDATE MARGINAL COST PROJECTIONS

MARGINAL COSTDEMAND-SIDEEVALUATIONS

MARGINAL COSTSUPPLY-SIDE

EVALUATIONS

RESOURCE MIX ANALYSIS AND OTHER

ECONOMIC EVALUATIONS

UPDATELOAD FORECAST

PUBLIC VERSION

17


The principal components in the process are as follows:

Update Marginal Cost Projections Based on Latest IRP

Marginal cost projections are derived using the previous IRP. These projections are then updated to

recognize any significant changes in costs such as fuel, technology, and regulatory compliance.

Load Forecast

A forecast of future energy and peak demand requirements for the next 20 years is developed.

This forecast incorporates an estimate of future economic conditions and trends in customer

energy usage.

Marginal Cost Demand-Side Evaluations

DSM programs (also referred to as demand-side options, or “DSOs”) are evaluated on a marginal cost

basis. This procedure is used to identify cost-effective DSM programs for inclusion in the IRP.

Marginal Cost Supply-Side Evaluations

Marginal cost evaluations are performed to determine if modifications to existing supply-side

resources or power purchases from other suppliers are economically viable.

Resource Mix Analysis and Benchmark Evaluations

This part of the IRP process involves the development of an optimal resource mix. The resource

mix is a flexible, iterative analysis that allows for integration of the appropriate combination of

resources that will serve the projected load at the lowest expected total cost (both fixed and

variable), while maintaining the target reliability guideline. This step includes sensitivity analyses

to establish boundaries within which the conclusions of a benchmark plan remain valid.

The resource mix analysis incorporates the impacts of existing and projected DSM programs,

revised load information, and updated cost information (including fuel, capital, operation and

maintenance). It also incorporates the most recent information on the characteristics of existing

resources, both supply-side and demand-side, as well as changes such as expected in-service dates

of resource additions, the expiration of PPA resources, and assumptions regarding future resource

PUBLIC VERSION

18


availability.7 The flexibility of the IRP process allows insertion of marginal cost results from the

supply-side or demand-side options in any sequence. The result is a benchmark plan that identifies

the most cost-effective combination of options, which in turn informs the Company’s decision-

making as it seeks to acquire or develop resources to address future needs.

In planning future resource additions, consideration is given to uncertainties associated with

unforeseen unit outages, abnormal weather, and load forecast deviations. In order to minimize the

effects of these uncertainties, criteria are established that qualify and quantify an appropriate level

of capacity reserves in both the summer and winter seasons. These reserves are planned to be

available to account for the potential inability to meet load requirements due to generation shortfalls

resulting from uncertainties inherent in the resource planning process. The minimum long-term target

reserve margin guideline, which is periodically reviewed and re-evaluated, is based on risk-adjusted

economic analyses, operating experience and system operation input, and seeks to minimize the

combined cost of new generating capacity, production costs, and customer-related costs associated

with outages while also ensuring the Company meets minimum reliability criteria thresholds.

Consistent with the updated Reserve Margin Study (discussed in greater detail in Section III.D), the

2019 IRP utilizes a minimum long-term Summer Target Reserve Margin of 16.25 percent for summer

periods and 26 percent for the minimum long-term Winter Target Reserve Margin. By virtue of

load diversity across the Southern System, the Summer Target Reserve Margin can be met if each

Operating Company maintains a long-term summer reserve margin of at least 14.89 percent. Similarly,

the Winter Target Reserve Margin can be met if each Operating Company maintains a long-term

winter reserve margin of at least 25.25 percent. In other words, Alabama Power can maintain a

long-term winter reserve margin of 25.25 percent but realize a level of reliability equivalent to 26

percent, thereby avoiding the cost of building or purchasing additional resources associated with the

0.75 percent differential. These capacity savings represent one of the many recognized benefits of

operating as part of the Southern Pool.

7 These assumptions are for study purposes only and do not reflect management decisions regarding the actual useful lives of such resources.

PUBLIC VERSION

19


Integration

Demand-side and supply-side options identified as cost-effective choices for resource additions,

but not previously reflected in the prior IRP’s benchmark plan, are incorporated in the IRP during the

integration phase. This phase consists of determining the Company’s best alternative for meeting the

resource needs identified in the benchmark plan, coordinating resource additions with those of the

other retail Operating Companies, and performing a financial assessment of the plan.

The process described above is not necessarily set forth in chronological order, as many evaluations

are performed concurrently. Marginal cost evaluations can be performed or updated at several points

in the process.

III.B. Load Forecast

The Company annually produces a short-term and long-term energy and peak demand forecast for

territorial customers of Alabama Power, including projections of customer growth, peak demand

(MW), and monthly energy consumption (kWh). The 2019 IRP reflects a 20-year load forecast for the

years 2019 through 2038.

Underlying this load forecast are economic data and forecasts supplied by IHS Markit. This information

includes available employment and demographic data as well as other economic indicators for the

state, all of which support the development of econometric models used to forecast the number

of customers, which is a major input to the load forecasting process. The other major input, per

customer electricity consumption, is less correlated with economic growth and more related to

trends in increased efficiency and other factors that are resulting in a decline in usage.

Alabama Power has traditionally been considered summer peaking, meaning its annual peak demand

has occurred during the summer months. However, in recent years, Alabama Power’s winter peak

demand has exceeded the summer peak demand. The 2014 actual winter peak was 12,610 MW (prior

to the utilization of interruptible and demand management options), which exceeded the prior all-

time peak of 12,496 MW that occurred in the summer of 2007. Indeed, weather normalization studies

indicate that the weather adjusted winter peak has exceeded the weather adjusted summer peak

since 2010. The Company’s most recent load forecast projects a winter peak demand that is between

PUBLIC VERSION

20


than the summer peak demand.

Figure III-B-1 represents the Company’s weather normalized historical summer and winter peak

demands since 2005, and clearly shows that weather adjusted winter peaks began to exceed summer

peaks as early as 2010. The graph also illustrates the Company’s forecasted winter and summer peak

demands from 2019 through 2038.

These projected rates are lower than those shown in the 2016 IRP, and reflect the effects of a slower

economic growth in the near term and, over the long term,

greater penetration of appliance and lighting efficiencies.

PUBLIC VERSION

21


2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

FIGURE III-B-1: Alabama Power Weather Normalized Historical Peak Demand with Forecast

Year

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

PUBLIC VERSION

22


2032

2033

2034

2035

2036

2037

2038

These forecast results are heavily dependent on the level of expected economic activity and

continued employment growth in the State of Alabama. Another influencing factor is continued

exports of products produced in Alabama (primarily transportation equipment), which is an important

consideration as Alabama remains a heavy manufacturing state.

III.C. Fuel Forecast

Both short-term (current year plus two) and long-term (year four and beyond) fuel and allowance

price forecasts are developed for use not only in the Company’s planning activities, but also in its

business case analyses and other applicable decisions. Short-term forecasts are updated monthly as

part of the Company’s fuel budgeting process and marginal pricing dispatch procedures. The long-

term forecasts are developed each year for use in the Company’s planning activities. Charles River

Associates (“CRA”), the Company’s scenario modeling consultant, produces the long-term fuel price

forecasts for natural gas and coal.

The development of the long-term forecasts is a highly collaborative effort between CRA, SCS, and the

retail Operating Companies. CRA’s MRN-NEEM national, multi-sector, energy-economy model, with

support from other CRA models, is used to generate integrated results for natural gas and coal prices,

in five-year increments, for the period 2023 through 2058. The integrated modeling approach makes

it possible to develop forecasts for natural gas and coal prices that are internally consistent with one

another and with other variables and feedbacks involving economic growth, electricity consumption,

and output across many sectors and regions. The integrated approach takes a set of assumptions

about market fundamentals and then solves for the prices that make the quantity supplied equal

PUBLIC VERSION

23


to the quantity demanded in all markets. In addition, the integrated approach simulates interactions

among different markets and thereby reveals how such things as environmental regulations and

natural gas supply outlooks shape the disposition of economic output across sectors, as well as the

competition between coal and natural gas as a generation fuel.

III.D. Reserve Margin

Electric utility customers expect and depend on a high level of service reliability. Accordingly, a

retail electric utility should have an economically balanced margin of generating capacity above its

anticipated peak load—the reserve margin. This enables the utility to maintain sustained reliability for

its customers, notwithstanding unexpected events such as equipment failures or extreme weather.

Reserve planning must be done on both a short-term and long-term basis, as the processes to procure

additional capacity can take several years. A reserve margin study facilitates the identification of an

appropriate amount of reserve capacity that should be targeted for any point in the future.

As for the System specifically, the maintenance of sufficient reserve capacity allows the Operating

Companies to serve customer demand reliably, even with the prevalence of unpredictable conditions

that can affect customer demand.

• Weather Uncertainty: The System’s “weather-normal” load forecasts are based on average

weather conditions over more than forty years. If the weather is hotter than normal during

warm seasons or colder than normal during cold seasons, the load will be higher. The System’s

peak demand can be as much as 6.6 percent higher in a hot summer year and 22 percent

higher in a cold winter year than in an average year.

• Economic Growth Uncertainty: It is difficult to project exactly how many new customers

will request electric service or how much power existing customers will use from season to

season. Based on historical projections and actual economic growth, peak demand may grow

• Unit Performance: While the Operating Companies maintain low forced outage rates for

their respective units, there have been occasions in the last ten years when

PUBLIC VERSION

24


of the capacity of the System has been in a forced outage state concurrently.

• Market Availability Risk: The ability to obtain resources on short notice from the market

when needed to address a System resource adequacy issue is uncertain. In general, having

access to resources in neighboring regions enhances a region’s reliability due to load and

resource diversity. However, the amount, cost, and deliverability of those resources are subject

to the external region’s resource-adequacy situation or transmission constraints at any given

time. While a region can expect some level of support from its neighbors, each region must

carry adequate reserves and manage its own reliability risks. This necessarily results in an

element of uncertainty regarding the availability of such external support when it is needed.

While each of these four factors creates a need for capacity reserves on its own, a confluence

of all these risk factors poses considerable risk. Very high capacity reserves would be required to

meet customers’ load demands plus operating reserve requirements to address the simultaneous

occurrence of all such events. However, the maintenance of such high levels of capacity reserves, in

an effort to eliminate all reliability risk, would come at significant expense.

A more appropriate approach to establish a reasonable reserve margin is to minimize the combined

costs of maintaining reserve capacity, system production costs, and customer costs associated with

service interruptions, and then adjust for the value at risk. This approach results in the Economic

Optimum Reserve Margin (“EORM”), properly adjusted for risk. However, that risk-adjusted EORM

must also meet a minimum reliability criteria threshold. Common practice in the industry regarding

this threshold is to plan for a Loss of Load Expectation (“LOLE”) of no greater than 0.1 days per year,

which is more commonly referred to in the industry as a one event in ten years criterion (“1:10 LOLE”).

As discussed earlier, the Company has historically relied upon a Target Reserve Margin only for the

summer season. However, the 2015 Reserve Margin Study results shown in the 2016 IRP identified

a significant increase in winter reliability risks due to several factors that had not previously been

incorporated in the reserve margin determination. These included: (1) the narrowing of the difference

between summer and winter weather-normal peak loads; (2) higher volatility of winter peak demands

relative to summer peak demands; (3) increased occurrence of unit outages due to cold weather; (4)

PUBLIC VERSION

25


greater penetration of solar resources; and (5) increased risk of fuel delivery disruption due to winter

conditions. Along with these, the 2018 Reserve Margin Study identified a sixth factor—decreased

supply alternatives from the wholesale power markets.

To address winter reliability issues, the Target Reserve Margin used in the 2016 IRP increased from 15

percent to 16.25 percent. Upon further consideration of the winter-related reliability risks, the Company

will now use an independent evaluation of resource adequacy in both the summer and winter peak

periods to ensure that System reliability is fully addressed. This results in the establishment of both

a Summer Target Reserve Margin and a Winter Target Reserve Margin.

Defining Target Reserve Margins

The traditional formulation of the Summer Target Reserve Margin is stated in terms of weather-

normal summer peak demands and summer capacity ratings according to the following formula:

STRM = TSC-SPL x 100%SPL

Where:

STRM = Summer Target Reserve Margin;

TSC = Total Summer Capacity; and

SPL = Summer Peak Load.

The Winter Target Reserve Margin is similarly derived, but uses weather-normal winter peak demands

and winter capacity ratings per the following formula:

WTRM = TWC – WPL x 100%WPL

Where:

WTRM = Winter Target Reserve Margin;

TWC = Total Winter Capacity; and

WPL = Winter Peak Load.

PUBLIC VERSION

26


Target Reserve Margins

After analyzing the load forecast and weather uncertainties, the cost of expected unserved energy,

and the projected generation reliability of the System, the Company is maintaining the current 16.25

percent long-term Target Reserve Margin for the System as the Summer Target Reserve Margin to be

applied to the summer peak planning season. To address the winter reliability concerns, the Company

is adding a long-term Winter Target Reserve Margin of 26 percent for the System to be applied to the

winter peak planning season. As explained in the 2018 Reserve Margin Study, the 26 percent long-term

Winter Target Reserve Margin is consistent with the results of the 2015 Reserve Margin Study.

For the short-term, the Company is increasing the Summer Target Reserve Margin from 14.75 to 15.75

percent, with a commensurate short-term Winter Target Reserve Margin of 25.5 percent. The smaller

gap between the long-term and short-term periods (regardless of season) is a direct consequence

of changing load characteristics and energy efficiency programs that have reduced the overall peak

demand response to economic uncertainty.

As noted earlier, one of the benefits of operating as part of the Southern Pool is that each Operating

Company can carry fewer reserves than the System target. Thus, the diversified Summer Target

Reserve Margin that applies to Alabama Power is 14.89 percent over the long-term and 14.39 percent

over the short-term. Similarly, the Company’s diversified Winter Target Reserve Margin is 25.25

percent over the long-term and 24.75 percent over the short-term. Changes in the load of each

Operating Company relative to the loads of the others can impact this diversification effect.

Figure III-D-1 depicts the projected winter and summer reserve margins for Alabama Power through 2038,

absent any resource additions. As the figure shows, the Company’s winter reserve margin is projected to

be below both its diversified long-term Winter Target Reserve Margin (25.25 percent) and its diversified

short-term Winter Target Reserve Margin (24.75 percent)

. Figure III-D-2

provides the corresponding capacity amounts that would address Alabama Power’s reliability deficits for

the winter periods. Resolving the shortfalls in the winter periods with resources available year-round will

also resolve the shortfalls occurring during corresponding summer periods shown on Figure III-D-3.

PUBLIC VERSION

27


FIGURE III-D-2: Alabama Power Projected Winter Capacity Needs

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029Winter Summer

2030 2031 2032 2033 2034 2035 2036 2037 2038 Winter Summer

FIGURE III-D-1: Alabama Power Projected Seasonal Reserve Margins

Capacity Need (MW) - Winter

Year APC Reserve Margin (%) APC Need (MW)2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038

PUBLIC VERSION

28


FIGURE III-D-3: Alabama Power Projected Summer Capacity Needs

Capacity Need (MW) - Summer

Year APC Reserve Margin (%) APC Need (MW)2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038

While the Southern Pool affords the participants the ability to rely on temporary surplus capacity

on the System, each Operating Company is expected to have adequate resources, including an

appropriate level of reserves, to reliably serve its own load obligations. Moreover, much of the

available “surplus” in the Southern Pool is made up of fossil steam resources that are under significant

cost pressures due to continued additional environmental compliance costs, coupled with forecasted

low gas prices and modest load growth. The retail Operating Companies that own these units may

decide at any point to retire some of the capacity on which Alabama Power might otherwise attempt

to rely. Alternatively, those companies could make wholesale sales predicated on some or all of that

capacity. In either case, the effect would be a reduction in the level of available capacity reserves on

the System. Accordingly, Alabama Power must address its reserve deficiency, and intends to do so

through appropriate action before the APSC.

PUBLIC VERSION

29


III.E. Emerging Resiliency Needs

The Company remains committed to maintaining a robust and resilient electric system that is capable

of reliably delivering electric energy, even in the face of unexpected events such as natural and man-

initiated disruptions. The Company has a history of managing and planning for reliability risk through

its reserve margin process, transmission planning analysis, and similar reliability studies, while also

demonstrating substantial commitment to infrastructure protection initiatives. As the Company’s

generating fleet continues to transition away from resources with on-site fuel storage, there is

increased fuel transportation risk associated with providing reliable electric service to customers.

Additionally, the threat of low probability, high-impact events (such as physical- and cyber-attacks

on electricity infrastructure) continues to grow.

At the bulk power system level, the Company routinely evaluates various contingencies as part of

its transmission planning process and proposes projects to mitigate the risks associated with these

contingencies. This level of planning meets or exceeds current North American Electric Reliability

Corporation (NERC) standards. However, as the Company’s generation resource mix continues to

transition, continued transmission planning considerations must be given to these changing conditions

to ensure future reliability and resilience of the bulk power system. The considerations could lead to the

inclusion of other planning alternatives, such as a more expansive use of inactive reserve or the addition

of fuel storage. Any actions, however, will be preceded by additional assessments of contingencies that

may affect the IRP, such as the simultaneous failure of multiple elements of the electricity supply chain

(e.g., transmission substations, gas pipelines, communication infrastructure, and generating stations). In

many cases, this level of assessment is beyond current NERC planning standards. The Company remains

committed to the reliable service of its customers, however, and will adapt as circumstances warrant.

III.F. Development of Indicative Resource Additions

In developing the benchmark plan, the Company begins with its existing resource portfolio,

including its active DSM programs, along with its forecast of future customer needs.8 For purposes

of identifying future resource additions, the Company evaluates established and emerging resource

8 An active DSM program is one that is dispatchable or controllable by the Company. In contrast, a passive DSM is an alternative adopted by customers that becomes embedded in their electric energy use patterns and requirements. The effects of passive DSM additions are captured in the load forecast in the form of peak load reduction megawatts.

PUBLIC VERSION

30


options. The objective is to assess their cost, status of development, safety, operational reliability,

flexibility, economic viability, fuel availability, construction lead times, and other factors.

The following is an overview of the screening process used to assess candidate technologies to

determine those suitable for further screening for potential inclusion as indicative resource options

in the expansion planning process.

• Preliminary Screening: The preliminary screening process identifies numerous technologies

for strategic assessment. This strategic and qualitative assessment considers the maturity of

the technology, construction lead times, operating characteristics, and financial requirements,

along with cost uncertainties, environmental costs, safety of construction and operation,

and resource availability. Many technologies from the initial list do not pass the preliminary

screening due to their limited applicability to the territory (e.g., ocean thermal generation) or

their early stage of development (e.g., magneto hydrodynamics).

• Secondary Screening: Technology options that pass the preliminary screening are then

retained for a secondary screening. Generic candidate options are identified using qualitative

factors such as scalability, repeatability, site requirements, and fuel availability. If a technology

has potentially desirable characteristics, but only under unique circumstances (or not readily

scalable and repeatable), then it will not pass the secondary screening and become a

generic candidate or receive a Levelized Cost of Energy (“LCOE”) analysis. Technologies that

have desirable characteristics under unique application settings, such as specific customer

requirements or geographic requirements, are retained separately to be evaluated for future

projects should the right set of circumstances arise.

The identified generic candidates will undergo additional screening using a LCOE analysis.

A LCOE analysis is a common industry method of using screening-level costs to provide an

indication of the economic viability of one generating technology option when compared

to others. LCOE models include both capital and operating costs relative to the energy

produced. The results can then be used to perform a relative comparison of generating units

with different operational profiles.

PUBLIC VERSION

31


• Expansion Planning Process: Candidate technology options retained after the secondary

screening become options for the expansion planning process. These options are further

screened using a busbar analysis to identify economic options over a range of capacity factors.9

Options selected at this stage are not, however, determinative of the resource or resources

that will ultimately be procured. Rather they serve to indicate the type(s) of resource(s) (and

the time needed for deployment) that may be required to meet an identified capacity need.

For the 2019 IRP, the above process yielded the following benchmark plan for Alabama

Power. As reflected in Figure III-F-1, the plan calls for the addition of combined cycle and CT

technologies totaling approximately 2,400 MW through 2028.

9 Intermittent resources, such as solar and wind, were not included as selectable technologies for the expansion planning model, but instead are evaluated pursuant to a separate analysis.

PUBLIC VERSION

32


The benchmark plan resulting from the 2019 IRP reflects the fact that the Company’s electric demand

(with necessary reserves) is materially higher than the Company’s winter capacity resources,

2019 IRPWinter Benchmark Base Case with Generic Additions

Year APC CT’s APC CC’s APC RM APC NEEDS (MW) ROC RM ROC NEEDS (MW)2020 - - 2021 - - 2022 - - 2023 300 - 2024 - - 2025 - 900 2026 - - 2027 600 - 2028 300 270 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038

FIGURE III-F-1: Alabama Power Winter Benchmark Plan

PUBLIC VERSION

33


Alabama Power cannot confidently rely on capacity reserves in the

Southern Pool to address its reliability needs. As discussed earlier, there are two reasons for this

conclusion. First, the Southern Pool affords the participants the ability to rely on temporary surplus

capacity on the System, but each Operating Company is expected to have adequate resources,

including an appropriate level of reserves, to reliably serve its own load obligations. Consistent with

this expectation, it is incumbent on Alabama Power to address significant and persistent shortfalls in

its required level of capacity reserves needed to provide adequate reliability for its own customers. A

second reason relates to the ongoing assurance of the available surplus in the Southern Pool. As stated

earlier, much of that surplus capacity comprises fossil steam resources that are under challenging cost

pressures for reasons including the ongoing cost of environmental compliance, forecasted low gas

prices, and modest load growth. The retail Operating Companies that own these units may decide at

any point to retire some of the capacity on which Alabama Power might otherwise attempt to rely.

Alternatively, those companies are free to make wholesale sales predicated on some or all of that

capacity. In either case, the effect would be a reduction in the level of available capacity reserves

on the System.

Accordingly, Alabama Power has concluded that a modest acceleration of the resource additions

indicated across the 2023 through 2028 time-frame will mitigate the described risks and better

facilitate its statutory duty to make reasonable enlargements of its system to meet the demand of

those customers for whom it holds a duty of service. Specifically, the Company intends to deploy

additional resources by the winter of 2024 to address its Target Reserve Margin shortfalls for both

the winter and summer seasons in a cost-effective manner. This plan already incorporates the effects

of additional active and passive DSM resources across the planning horizon. The Company presently

is working to identify the exact resources to respond to this need, including cost-effective demand-

side opportunities. When the most appropriate resources are identified, the Company will file a

petition for a certificate of convenience and necessity with the APSC requesting authorization to

proceed with the resource additions.

PUBLIC VERSION

34


IV. CONCLUSION

The 2019 IRP process has identified certain capacity needs for Alabama Power.

In particular, the Company’s Winter Target Reserve Margin is well below its diversified winter target

planning reserve margin guideline in the planning timeframe, signaling a significant need to add

reserve capacity to address its winter reliability concerns. Consistent with its obligation to provide

reliable service to its customers, the Company intends to pursue the necessary and appropriate

measures to satisfy those needs. By doing so, Alabama Power will be in a position to continue meeting

the demands of its customers in a reliable manner over the 20-year planning horizon, consistent with

its statutory duty of service to its customers.

PUBLIC VERSION

35


APPENDIX 1

Alabama Power CompanyExisting Supply-Side

Resources

PUBLIC VERSION

A1-1


FIGURE A1-1: Alabama Power Company Existing Supply-Side Resources(as of April 30, 2019)

Alabama Power Company Owned & Contracted Resource Summary Nameplate/ Contract Plants Units Capacity (MW) Fossil 9 31 7,837 Nuclear 1 2 1,720 Hydro 14 41 1,668 Solar 2 2 18 Ownership Total 26 76 11,243 Contracted Total N/A N/A 1,546 Total Owned & Contracted 12,788

Fossil Steam Plants Nameplate Capacity n-ServicePlant Units (MW) Year NotesBarry 1 125 1954 Barry 1 restored to active service in 2019 2 125 1954 Barry 2 restored to active service in 2019 4 350 1969 5 700 1971 Gadsden 1 60 1949 2 1949 Gadsden 2 unavailable after Spring 2019Gaston 1 125 1960 Ratings reflect 50% Alabama Power operating capacity; 100% owned by Southern Electric Generating Company (SEGCO) 2 125 1960 Ratings reflect 50% Alabama Power operating capacity; 100% owned by Southern Electric Generating Company (SEGCO) 3 125 1961 Ratings reflect 50% Alabama Power operating capacity; 100% owned by Southern Electric Generating Company (SEGCO) 4 125 1962 Ratings reflect 50% Alabama Power operating capacity; 100% owned by Southern Electric Generating Company (SEGCO) 5 880 1974 Gorgas 8 1956 Gorgas 8 retired April 15, 2019 9 1958 Gorgas 9 retired April 15, 2019 10 1972 Gorgas 10 retired April 15, 2019Greene County 1 150 1965 Ratings reflect Alabama Power 60% ownership 2 150 1966 Ratings reflect Alabama Power 60% ownershipMiller 1 606 1978 Ratings reflect Alabama Power 91.8% ownership 2 606 1985 Ratings reflect Alabama Power 91.8% ownership 3 660 1989 4 660 1991 Total 16 5,572

Nuclear Steam Plants Nameplate Capacity n-ServicePlant Units (MW) Year NotesFarley 1 860 1975 2 860 1979 Total 2 1,720

PUBLIC VERSION

A1-2


Alabama Power Company Supply-Side Resource Summary - cont.

Gas-Fired Plants (Combustion Turbines) Nameplate Capacity In-ServicePlant Units (MW) Year NotesGreene County 2 80 1996 3 80 1996 4 80 1995 5 80 1995 6 80 1995 7 80 1995 8 80 1996 9 80 1996 10 80 1996Total 9 720

Gas-Fired Plants (Combined Cycles) Nameplate Capacity In-ServicePlant Units (MW) Year NotesBarry 6 535 2000 7 535 2001 Washington County 1 123 1999 Co-generation plantLowndes County 1 105 1999 Co-generation plant located at SABIC Innovative Plastics (formerly GE Plastics)Theodore 1 236 2001 Co-generation plant Total 5 1,535

Contracted Capacity Nameplate Capacity n-ServicePlant (MW) Year NotesCalhoun Power PPA 700 2003 Westervelt PPA 8 2012 Chisholm View PPA 202 2013 Buffalo Dunes PPA 202 2014 LaFayette PPA 72 2017 Other 362 Represents net capacity that the Company has rights to through various contractsTotal 1,546

Oil-Fired Plants (Combustion Turbines) Nameplate Capacity n-ServicePlant Unit (MW) Year NotesGaston A 10 1970 Ratings reflect 50% Alabama Power operating capacity; 100% owned by Southern Electric Generating Company (SEGCO) Total 1 10

Solar Powered Facilities Nameplate Capacity In-ServicePlant Unit (MW) Year NotesFort Rucker 10.6 2017Anniston Army Depot 7.4 2017Total 2 18

PUBLIC VERSION

A1-3


Hydro Electric Plants Nameplate Capacity In-ServicePlant Units (MW) Year NotesWeiss 1 29.25 1962 Upper Coosa Group 2 29.25 1961 Upper Coosa Group 3 29.25 1961 Upper Coosa GroupHenry 1 24.3 1966 Upper Coosa Group 2 24.3 1966 Upper Coosa Group 3 24.3 1966 Upper Coosa GroupLogan Martin 1 45 1964 Upper Coosa Group 2 45 1964 Upper Coosa Group 3 45 1964 Upper Coosa GroupLay 1 29.5 1968 Lower Coosa Group 2 29.5 1968 Lower Coosa Group 3 29.5 1967 Lower Coosa Group 4 29.5 1967 Lower Coosa Group 5 29.5 1967 Lower Coosa Group 6 29.5 1967 Lower Coosa GroupMitchell 4 20 1949 Lower Coosa Group 5 50 1985 Lower Coosa Group 6 50 1985 Lower Coosa Group 7 50 1985 Lower Coosa GroupJordan 1 25 1928 Lower Coosa Group 2 25 1928 Lower Coosa Group 3 25 1928 Lower Coosa Group 4 25 1928 Lower Coosa GroupBouldin 1 75 1967 Lower Coosa Group 2 75 1967 Lower Coosa Group 3 75 1967 Lower Coosa GroupMartin 1 46 1926 Tallapoosa Group 2 41 1926 Tallapoosa Group 3 40 1926 Tallapoosa Group 4 55 1952 Tallapoosa GroupThurlow 1 34.02 1930 Tallapoosa Group 2 34.02 1930 Tallapoosa Group 3 12.96 1930 Tallapoosa GroupYates 1 23.5 1928 Tallapoosa Group 2 23.5 1928 Tallapoosa GroupHarris 1 66 1983 Tallapoosa Group 2 66 1983 Tallapoosa GroupSmith 1 78.75 1961 Warrior Group 2 78.75 1962 Warrior GroupBankhead 1 53.985 1963 Warrior GroupHolt 1 46.944 1968 Warrior GroupTotal 41 1,668

Alabama Power Company Supply-Side Resource Summary - cont.

PUBLIC VERSION

A1-5


APPENDIX 2

Alabama Power CompanyDemand-Side Management Programs

PUBLIC VERSION

A2-1


Alabama Power is committed to both economic growth and environmental stewardship within the

state. In concert with customer needs and desires, Alabama Power works to ensure that it continues

to have the reliable and cost-effective energy needed to promote the interests of the region. In

doing so, Alabama Power continues to be an industry leader in cost-effective DSM programs. The

Company implements DSM measures and programs that are designed to reduce customers’ energy

bills, improve their competitiveness, assist with system load shape management (thereby reducing

costs and the need for future capital investment), and help customers use energy as efficiently as

possible. All customer segments (industrial, commercial, and residential) are potential participants in

these programs.

Changes in technology and other influencing factors can, along with education, provide opportunities

for the Company to work more with customers to help them manage and control their energy use,

making it more efficient and economical. In managing its DSM programs, Alabama Power must be

mindful of the effect they can have on electricity prices. Accordingly, the Company pursues those

programs that are expected to benefit all of its customers, thereby avoiding the situation where

some customers are effectively being caused to subsidize the benefits realized by others.

The economic health of all customers is not only important to Alabama Power, but also to the state

and its future economic vitality. Therefore, future DSM programs can be expected to continue to

balance these considerations in a cost-effective manner – encouraging customers’ wise and efficient

use of energy, while maintaining an economically vibrant and productive region.

Alabama Power currently has customers participating in more than 15 DSM programs in the residential,

commercial, and industrial sectors, as well as programs managed through the Company’s Distribution

Operations. The 2019 IRP includes approximately 1,511 MW of existing contracted active demand-side

programs that have allowed the deferral of 1,219 MW of supply-side resource capacity in the winter.

The difference between the nominal values shown for the demand-side programs and the associated

supply-side resource capacity deferrals is due to the lower availability of capacity equivalence under

DSM program, as compared to a supply-side resource. As noted earlier, DSM programs that are

subject to the direct control of the Company (e.g., non-residential interruptible load) are called

“active DSM.” The DSM programs dependent on customer behavior or energy usage patterns (e.g.,

PUBLIC VERSION

A2-2


equipment SEER efficiency increases, insulation/infiltration upgrades) are called “passive DSM.” The

passive DSM programs serve to reduce expected peak load and consequently are embedded in the

Company’s load forecast. Existing passive DSM programs are estimated to have resulted in a winter

peak load reduction of 363 MW. Therefore, the total amount of existing DSM programs reflected in

the 2019 IRP is 1,511 MW plus 363 MW, for a total of 1,874 MW.

Active DSM Programs

The capacity values associated with the Company’s active DSM programs, as reflected in the

2019 IRP, are shown in Figure A2-1 Winter and Figure A2-1 Summer, followed by a description of

those programs.

PUBLIC VERSION

A2-3


FIGURE A2-1 WinterINTEGRATED RESOURCE PLAN - 2019

Projections of Active Demand-Side Options (DSOs) 2019-2038

Active DSOs 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Contract Amounts Resource Deferral Amounts

2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 Contract Amounts Resource Deferral Amounts

Active DSOs - Contract Amounts 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Rate Real Time Pricing (RTP) 150 & 200 Hour Interruptible 600 Hour Interruptible Non-Indust. Direct Load Control Customer Standby Generation Distribution Regulation Option Program (DROP) Total Active DSO - Contract Amount

2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 Rate Real Time Pricing (RTP) 150 & 200 Hour Interruptible 600 Hour Interruptible Non-Indust. Direct Load Control Customer Standby Generation Distribution Regulation Option Program (DROP) Total Active DSO - Contract Amount

Active DSOs - Resource Deferral Amounts 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Rate Real Time Pricing (RTP) 150 & 200 Hour Interruptible 600 Hour Interruptible Non-Indust. Direct Load Control Customer Standby Generation Distribution Regulation Option Program (DROP) Total Active DSO - Resource Deferral Amount

2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 Rate Real Time Pricing (RTP) 150 & 200 Hour Interruptible 600 Hour Interruptible Non-Indust. Direct Load Control Customer Standby Generation Distribution Regulation Option Program (DROP) Total Active DSO - Resource Deferral Amount

Active Demand-Side Options are those activated, i.e., dispatchable or controllable, by the Company at the time of need.Active DSOs are explicitly indicated in the Integrated Resource Plan (IRP) as a resource. Active DSOs reflected here are inputs for the 2019 IRP.

PUBLIC VERSION

A2-4


FIGURE A2-1 SummerINTEGRATED RESOURCE PLAN - 2019

Projections of Active Demand-Side Options (DSOs) 2019-2038

Active DSOs 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Contract Amounts Resource Deferral Amounts

2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 Contract Amounts Resource Deferral Amounts

Active DSOs - Contract Amounts 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Rate Real Time Pricing (RTP) 150 & 200 Hour Interruptible 600 Hour Interruptible Non-Indust. Direct Load Control Customer Standby Generation Distribution Regulation Option Program (DROP) Total Active DSO - Contract Amount

2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 Rate Real Time Pricing (RTP) 150 & 200 Hour Interruptible 600 Hour Interruptible Non-Indust. Direct Load Control Customer Standby Generation Distribution Regulation Option Program (DROP) Total Active DSO - Contract Amount

Active DSOs - Resource Deferral Amounts 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Rate Real Time Pricing (RTP) 150 & 200 Hour Interruptible 600 Hour Interruptible Non-Indust. Direct Load Control \Customer Standby Generation Distribution Regulation Option Program (DROP) Total Active DSO - Resource Deferral Amount

2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 Rate Real Time Pricing (RTP) 150 & 200 Hour Interruptible 600 Hour Interruptible Non-Indust. Direct Load Control Customer Standby Generation Distribution Regulation Option Program (DROP) Total Active DSO - Resource Deferral Amount

Active Demand-Side Options are those activated, i.e., dispatchable or controllable, by the Company at the time of need.Active DSOs are explicitly indicated in the Integrated Resource Plan (IRP) as a resource. Active DSOs reflected here are inputs for the 2019 IRP.

PUBLIC VERSION

A2-5


DESCRIPTION OF ACTIVE DSM PROGRAMS

Residential Demand Response Programs:

1. Centsable Switch – A cycling program whereby a customer’s HVAC is cycled 67 percent

during the months of June through September up to 5 hours per day, subject to a maximum

of 150 hours per year.

2. SmartPower Critical Peak Pricing Program – Participating customers receive service under

a time-of-use rate with a critical peak price (“CPP”) component, and are incented to manage

their load during critical peak periods through the issuance of price signals from the Company.

Commercial and Industrial Demand Response Programs:

1. Industrial Interruptible Program – This program, which is currently one of the largest of

its kind in the nation, allows Alabama Power to call for the interruption of load with 15 to 30

minutes’ notice. The Company’s right to interrupt is subject to contractual limitations (e.g., no

more than 200 to 600 hours per year and no longer than 8 hours per call).

2. Real Time Pricing – Industrial pricing option based on marginal costs plus applicable

adders to recover fixed costs.

3. Standby Generator Program – Under this program, customers enter into a contract with

Alabama Power to switch to their standby generators with no notice for use in non-emergency

circumstances. The Company is limited to calling these contracts for not more than 200 hours

a year (not including maintenance and testing), with no call exceeding 8 hours.

4. Supplemental Reserves – Less than 15-minute interruptible load that can be called as

needed to support system operations.

Transmission and Distribution Energy Efficiency Programs:

1. Distribution Regulation Optimization Program (“DROP”) – A conservation voltage

control option that lowers the voltage on distribution feeders to lower the demand and

reduce Volt Ampere Reactive (“VAR”) requirements on the system. The target activation

periods under this program are the summer and winter peaks.

PUBLIC VERSION

A2-6


Active DSM Pilot Programs – The Company is currently conducting the following pilot programs

with small test groups within the residential class to assess the potential for active DSM in the winter.

1. Power Pause – The Power Pause pilot officially started on June 1, 2019. The premise behind

the pilot is the development of a residential interruptible program that can be utilized not

only for summer months, but also for winter and shoulder months. The current program is

limited to employees taking service from the Company and only applies to customers with

a 200-amp service. Beginning in 2020, a 400-amp meter should be available and will allow

the Company to extend the pilot to additional participants. The pilot allows the Company,

using remote connect/disconnect (“RCDC”) meters, to interrupt electric service to participants

subject to the following parameters:

• Months Available – January to December

• Total Annual Interruptible Hours – 40 Hours

• Maximum number of Hours per Event – 4 Hours

• Maximum events in a day – 2 Events

• Available Time Periods – Monday – Friday (24 Hours per Day)

• Excluded Time Periods – Holidays and Weekends.

2. Residential Water Heater Pilot – The Residential Water Heater pilot is expected to start

later this year (2019). The goal of the pilot is to study electric water heating usage patterns

of the Company’s customers and then accommodate those patterns in a way that reduces

overall electrical demand without adversely impacting the availability of hot water for those

customers. Based on the participant’s hot water usage pattern, the participant will be placed

in a specified group. The Company will then manage the water heater demand of the various

groups using switches that control the electric elements and temperature, providing an

opportunity for peak load shaving throughout the year.

PUBLIC VERSION

A2-7


Passive DSO Impacts 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Residential Energy Efficiency Programs Commercial Energy Efficiency Programs Industrial Energy Efficiency Programs Peak (MW) Winter

2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 Residential Energy Efficiency Programs Commercial Energy Efficiency Programs Industrial Energy Efficiency Programs Peak (MW) Winter

Passive DSM Programs

The projected load reductions associated with the Company’s passive DSM programs, as embedded

in the load forecasts underlying the 2019 IRP, are shown in Figure A2–2 Winter and Figure A2–2

Summer, followed by a description of those programs.

FIGURE A2-2 WinterINTEGRATED RESOURCE PLAN - 2019

Projections of Passive Demand-Side Options (DSOs) 2019-2038

Gross Peak Load 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 PEAK (MW) Winter

2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 PEAK (MW) Winter

Net Peak Load 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 PEAK (MW) Winter

2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 PEAK (MW) Winter

Passive DSOs are those alternatives adopted by customers that become inherent in their electric energy use pattern and requirements. Passive DSOs are embedded in the Company’s load forecast and enumerated in the Integrated Resource Plan.

PUBLIC VERSION

A2-8


Passive DSO Impacts 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Residential Energy Efficiency Programs Commercial Energy Efficiency Programs Industrial Energy Efficiency Programs Peak (MW) Summer

2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 Residential Energy Efficiency Programs Commercial Energy Efficiency Programs Industrial Energy Efficiency Programs Peak (MW) Summer

FIGURE A2-2 SummerINTEGRATED RESOURCE PLAN - 2019

Projections of Passive Demand-Side Options (DSOs) 2019-2038

Gross Peak Load 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 PEAK (MW) Summer

2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 PEAK (MW) Summer

Net Peak Load 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 PEAK (MW) Summer

2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 PEAK (MW) Summer

Passive DSOs are those alternatives adopted by customers that become inherent in their electric energy use pattern and requirements. Passive DSOs are embedded in the Company’s load forecast and enumerated in the Integrated Resource Plan.

Residential Energy Efficiency Programs:

1. Smart Neighborhood Builder Program – This program promotes the installation of heat

pumps and electric water heaters in new homes that are constructed to meet a Home Energy

Rating System (“HERS”) Index of 65 or below. A typical home built to the 2006 International

Energy Conservation Code (“IECC”) would be given a HERS rating of 100. Each point of

reduction in the HERS index represents a one percent increase in energy efficiency. Therefore,

a Smart Neighborhood home is at least 35% more efficient than a typical home built to the

2006 IECC. Additionally, Smart Neighborhood homes feature smart home devices, such

PUBLIC VERSION

A2-9


as smart thermostats and smart light switches, which allow homeowners to monitor and

control their energy usage from their mobile device.

2. Heat Pump Water Heater Program – This program promotes the installation of heat

pump water heaters which uses energy efficient heat pump technology to transfer heat from

the surrounding environment to the water.

3. Tankless Water Heater Program – This program promotes the installation of electric

tankless water heaters in new construction. Electric tankless water heaters heat water when

it is needed instead of holding the water in a tank.

4. Residential Time Advantage Rates – Time Advantage Rates provide pricing signals by

time period to incent customers to shift their usage to lower cost periods.

5. Residential Plug-in Electric Vehicle Rate Rider – The rider offers a daily 1.7155 cent/kWh

discount on the customer’s whole house electric usage between the hours of 9pm and 5am

to incent the customer to charge their electric vehicle(s) during off-peak hours.

Residential Customer Value Programs:

1. In-Home Energy Check-Up – This program provides for in-home energy audits performed

by Alabama Power Energy Sales and Efficiency personnel.

2. Online Energy Check-Up – This program makes an on-line energy audit available to all

residential customers.

Commercial Energy Efficiency Programs:

1. Energy Star Cooking – This program promotes Energy Star cooking equipment in the

commercial market.

2. Heat Pump Water Heater Program –This program promotes heat pump water heaters in

the commercial market.

3. Business Time Advantage Rates – Time Advantage Rates provide pricing signals by time

period to incent customers to shift their usage to lower cost periods.

Commercial and Industrial Customer Value Programs:

1. In-Business Energy Check-Up (Commercial) – This program makes available an in-

business energy audit performed by Alabama Power Energy Sales and Efficiency personnel.

PUBLIC VERSION

A2-10


2. Smart Energy Use Program (Industrial) – This program provides customers with an

evaluation of their manner (equipment type or technology application) and practices of

energy consumption.

Transmission and Distribution Energy Efficiency Programs:

1. Distribution Energy Efficiency Program (“DEEP”) – DEEP operates continuously using

capacitors to reduce voltage drop on distribution feeders. The lower voltage upstream of

distribution feeders lowers the demand and reduces VAR requirements on the system.

Alabama Power’s overarching goal as an electric supplier is to maintain high reliability at cost-

effective rates, while providing exceptional customer service. With respect to energy efficiency,

the Company supports reasonable building codes and appliance standards that result in customers

becoming more efficient in their use of electricity. Alabama Power also works with its customers

to help them learn ways to better manage their energy usage and thereby become more efficient

users. As part of these efforts, the Company’s energy efficiency programs are reasonably expected

to benefit all customers, enabling them to realize lower rates than would have been the case had

other alternatives been pursued (either supply side or demand side).

PUBLIC VERSION

A2-11


APPENDIX 3

Alabama Power CompanyProcurement of

Renewable Resources

PUBLIC VERSION

A3-1


Consistent with the 2013 and 2016 IRPs, the Company continues to explore adding to its generation

mix renewable resources that are projected to bring benefits to customers. This strategy is evidenced

by the Company’s procurement and development of over 500 MW of renewable energy since

2011. Under these projects, the Company has rights to the environmental attributes, including the

renewable energy certificates (“RECs”), associated with the energy. Alabama Power can retire some,

or all, of these environmental attributes on behalf of its retail electric customers or it can sell the

environmental attributes, either bundled with energy or separately, to third parties.

The Company’s renewable resource strategy also reflects action taken by the APSC. On September 16,

2015, the Commission issued to the Company a certificate of convenience and necessity in Docket No.

32382 authorizing the development or procurement of up to 500 MW of capacity and energy from

renewable energy and environmentally-specialized generating resources. Projects presented to the

Commission for approval pursuant to the certificate must satisfy certain eligibility criteria. First, the

project must involve a renewable energy resource (such as those identified in Alabama Code § 40-18-

1(30)) or an environmentally specialized generating resource (such as combined heat and power) and

be no larger than 80 MW (measured in alternating current (“AC”) terms). Second, the project must meet

certain economic benefits criteria, namely, that it is expected to result in a positive economic benefit

for all of Alabama Power’s customers. The APSC will consider projects up to 160 MW of the certificated

amount annually; any proposal in excess of that annual threshold requires prior authorization. In

addition, any unexercised authority under the certificate expires after six years.

Consistent with the certificate authority in Docket No. 32382, the APSC subsequently approved two

projects on December 14, 2015. Specifically, on December 14, 2015, the APSC authorized Alabama

Power to construct and own two solar facilities at army installations served by the Company, which

were placed into commercial operation in 2017. Fort Rucker was placed into service on April 1, 2017

at 10.6 MW and Anniston Army Depot (“ANAD”) was placed into service on July 14, 2017 at 7.4 MW.

Additionally, on June 9, 2016, the APSC approved a power purchase agreement (“PPA”) for the output

of a solar facility near the town of LaFayette in Chambers County, which went into commercial

operation on December 15, 2017 at 72 MW. These solar projects are reflected in this 2019 IRP. Alabama

Power is receiving all energy and associated RECs generated by these projects, which it uses to serve

its customers with solar energy and also sells portions to third parties for the benefit of customers.

PUBLIC VERSION

A3-2


Also, pursuant to the certificate authority in Docket No. 32382, the Company will continue to consider

and evaluate other projects that would satisfy the criteria set forth in the Commission’s certificate

order through biannual Renewable Requests for Proposals (“RFPs”). Qualifying proposals submitted

through these RFPs will afford Alabama Power an opportunity to review market offerings and

determine whether there are economic and viable energy projects suitable for pursuit consistent

with the requirements of the order.

The Company will continue to consider and evaluate projects that resulted from the 2016 or 2018

RFPs and unsolicited bids for projects that would satisfy the criteria set forth in the Commission’s

certificate order. Additional renewable resources will be added to its plan as they are identified,

either through the exercise of the authority under that certificate or through another vehicle.

PUBLIC VERSION

A3-6


PUBLIC VERSION


Exhibit JBK-2

PUBLIC VERSION

1


2018

CAPACITY REQUEST FOR PROPOSALS

Issued: September 21, 2018

Forecasting and Resource Planning


600 North 18th Street

Birmingham, AL 35203

PUBLIC VERSION

2

TABLE OF CONTENTS

Introduction ................................................................................................. 3

Confidentiality ............................................................................................. 4

Communications ........................................................................................... 5

Operational Parameters and Requirements .................................................. 6

Power Purchase Agreement Proposals ......................................................... 8

Asset Purchase and Sales Agreement Proposals ......................................... 21

Notice of Intent to Bid (“NOI”) Submittal Process ....................................... 24

Bid Evaluation ............................................................................................. 25

Company’s Reservation of Rights and Disclaimers ...................................... 26

Target Solicitation Schedule ........................................................................ 27

Guidance to Bidders and Instructions for Completing Forms ...................... 27

Compliance with Laws; Regulatory Approvals ............................................. 30

Frequently Asked Questions (“FQAs”) ......................................................... 30

RFP Attachments Summary......................................................................... 32

Attachment A: Non-Price and Other Qualitative Considerations

Attachment B: Notice of Intent to Bid (“NOI”) Forms

Attachment C: RFP Bid Forms

Attachment D: Interconnection Information Summary

Attachment E: Environmental Assessment Questionnaire

Attachment F: Stability Analysis Information

Attachment G: Pro Forma PPA

Attachment H: Bidder Fees and Due Diligence

PUBLIC VERSION

3

Introduction

Alabama Power Company (“Company”) hereby announces the 2018 Request for Proposals

(“RFP”) for resources of a capacity rating between one hundred megawatts (100 MW) and

twelve hundred megawatts (1,200 MW). Qualifying proposals submitted through this RFP

will afford Alabama Power Company an opportunity to review market offerings to

determine whether there are economic and viable energy projects suitable to provide

reliable, dispatchable, cost-effective capacity and energy resources to meet the needs of its

customers. The Company is seeking capacity that is available to commence service in the

2019-2023 timeframe, with the amount depending upon the cost competitiveness of the

respective offers as well as options available to the Company. The Company is interested

in proposals for:

(A) Power purchase agreements (“PPAs”) from electric generation facilities;

and

(B) Asset purchase and sale agreements (“APSAs”) for both: (i) existing

generation facilities; and (ii) new-build/transfer electric generation facilities

(i.e., new facilities to be constructed that will be acquired after substantial

completion through a purchase transaction).

All proposals must be for resources that, at a minimum, meet established reliability and

performance criteria and that can be dispatched on demand (with appropriate notification)

by the Company. Each project proposed must be at least one hundred megawatts (100

MW) in size and no single resource should exceed twelve hundred megawatts (1,200 MW).

Proposals may encompass any type of energy source. The Company is seeking proposals

from projects that will be available and dispatchable to meet capacity needs for both its

summer (June – September) and winter (December – February) peak demands. This RFP

is not open to any affiliate of the Company, including but not limited to Southern Power

Company.

Nothing in this RFP or in the associated materials provided should be considered an offer

or acceptance of terms or conditions of a PPA, an APSA, an interconnection agreement, or

any other contract or business arrangement. Any proposal that does not satisfy the

requirements of this RFP may be considered nonresponsive, and the Company reserves the

right to reject any such proposal without opportunity for correction or cure. The Company

may, but is under no obligation to, contact any bidder to obtain additional information

regarding its proposal. Each participating bidder waives any and all right of recourse

against the Company, its parent, and any of their affiliates or subsidiaries (including their

officers, directors, employees, agents and representatives for either rejection of the

proposal or for failure to execute an agreement with the bidder for any reason. The

Company shall have no obligation or liability to any bidder unless and until a definitive

agreement with such bidder has been successfully negotiated, fully executed, and any and

all conditions precedent and subsequent to the effectiveness of such agreement are

satisfied. The Company reserves the right, in its sole discretion, to determine whether to

pursue negotiation and execution of any agreement with any bidder. Further, any

PUBLIC VERSION

4

agreement shall be subject to all requisite management approvals of the Company as well

as approval by the Alabama Public Service Commission (“APSC”) in a form suitable to

the Company, in its sole discretion. Proposals submitted pursuant to this RFP will be

evaluated in a manner deemed appropriate by the Company, including but not limited to

evaluations that measure proposals against one another on a like-kind basis (independent

of technology type) and against other power supply options that may be available to the

Company. Such other power supply options may include generation resources owned or

developed by the Company, other generation resources located in the service territories of

the Company and its affiliates, and other proposals for firm capacity generation that are

provided to the Company outside of this RFP process. The Company is under no obligation

to select any project, nor is the Company limited to choosing from the proposals submitted

in response to this RFP. The Company may determine in its sole discretion to exclusively

procure firm capacity resources outside of this RFP process, or to defer the pursuit of any

resources, through proposals identified in this RFP or otherwise, until a future date

determined by the Company.

Confidentiality

Participation in this RFP is conditioned on the execution of a standard Confidentiality

Agreement, a copy of which is being provided for each bid type proposal being solicited

in Attachment B: Notice of Intent to Bid (“NOI”) Forms.

The Company will take reasonable precautions and use reasonable efforts to protect any

proprietary and/or confidential information contained in a bid proposal provided that the

bidder clearly identifies such information as confidential on the page on which it appears.

The Company may, however, be required to make such confidential information available

under applicable state and/or federal law to regulatory commission(s), their respective staff

or other governmental agencies having jurisdiction. In addition, the Company reserves the

right to release such information to agents or contractors of the Company, for the purpose

of market resource assessment and evaluation of bid proposals, or to regulated retail

affiliates seeking similar supply-side resources. The Company further reserves the right to

share generating facility specific information with a new facility owner if the seller assigns

or otherwise transfers control of the facility to a new owner. Under no circumstances will

the Company, its parent company, affiliates, subsidiaries, and the officers, directors,

employees, agents or representatives of any of them be liable to any party for any damages

resulting from any disclosure of information provided in response to this RFP before,

during or after the solicitation process. In the event the winning bidder elects to sell the

generating facility that is the subject of the proposal, the Company may share the winning

bidder’s confidential information (i.e., information on operations, reliability, etc.) with

prospective buyers who are identified by seller, to ensure future performance in accordance

with the applicable agreement

PUBLIC VERSION

5

Communications

Prior to the Submission of Bids

All questions to the Company regarding the RFP should be submitted utilizing the “Contact

Us” link on the RFP website, www.alabamapower.com/our-company/how-we-

operate/capacity-rfp.html. Properly submitted questions along with the appropriate

responses will be recorded in a bidders question and answer form and periodically sent to

bidders from the Company via email from [email protected]. Other than

questions and answers submitted using the “Contact Us” link on the RFP website, no other

explanations or interpretations of this RFP will be given. Questions will be accepted by

the Company until five (5) business days (November 2, 2018) before the date on which bid

proposals are due.

The RFP document and its Attachments A-H will be made available on the RFP website.

All bidders must submit the required Notice of Intent to Bid (“NOI”) forms by October 5,

2018 by 5:00 p.m. CDT. Bidders failing to submit an NOI by this time date may have their

proposals summarily rejected by the Company, in its sole discretion. The Company will

allow bidders to list up to a maximum of three individuals as contacts during the RFP

process. The contact information for these individuals must be included in the required

NOI form “Contact(s) for RFP Process” in Attachment B.

All bidders should familiarize themselves with this RFP document and all its attachments,

located on the RFP website (www.alabamapower.com/our-company/how-we-

operate/capacity-rfp.html). Interested parties are expected to be able to download this RFP

with its required attachments, complete the attachment forms and submit the attachment

forms via email to [email protected] and one hardcopy via mail by the RFP

deadline of November 9, 2018 by 5:00 pm CST to the Company. All bidders should refer

to this RFP document for guidance in the event there are any differing of references

between this RFP document and its attachments.

Emailed files CANNOT be received as a .ZIP file, be greater than 20MB in size, or posted

in a file sharing folder (e.g., DropBox®1 or Google Docs™2).

Any and all communications regarding this RFP should be submitted through the above-

referenced process. Attempts at direct communications with the Company or Southern

Company Services regarding the RFP will be disregarded.

Following the Submission of Bids

All communications with bidders following the submission of bids shall be conducted

through the Company and shall be confidential. Such communications may include one or

more face-to-face meetings with each bidder, attended by the Company and other Company

1 DropBox is a U.S. registered trademark for DropBox, Inc 2 Google Docs is a trademark of Google LLC

PUBLIC VERSION

http://www.alabamapower.com/our-company/how-we-operate/capacity-rfp.html




mailto:[email protected]








6

representatives and advisors, in order to discuss the bidder’s proposal(s). In addition to or

in lieu of face-to-face meetings, the Company and other Company representatives or

advisors also may conduct telephonic conference calls with a bidder in order to clarify bid

proposals or resolve issues with such bid proposals.

Following the Execution of the Final Contract

Winning bidders may not announce the execution of any final PPA or APSA via a press

release or any other method of public communication without prior approval of the

Company.

Operational Parameters and Requirements

The Company is seeking RFP resources that can meet the operational requirements and

parameters described in this section in order to meet the Company’s reliability needs in

both the winter and summer. All bid proposals should provide all pertinent operational

information and should identify any inability to meet one or more criteria set forth in the

“Operating Parameters” tab of Attachment C: RFP Bid Forms.

Minimum and Maximum Capacity Limits of Resources

Each project proposal, including an aggregate of units at a facility, must be at least one

hundred megawatts (100 MW) in total capacity for the resource proposed, and no single

resource should exceed twelve hundred megawatts (1,200 MW).

Seasonal Availability and Capability

All bid proposal projects must provide the capacity ratings of the facility for the

summer (June-September) and winter (December-February) seasons. For the winter

season, the capacity ratings can be in the form of a separate winter season capacity

rating, guaranteed output at various low temperatures, or a guarantee of “as capable”

output with an associated temperature-output engineering curve. For PPAs, the

resources must be available year-round, and not be subject to scheduled outages in

either the winter or summer seasons.

AGC Requirements

All proposals must be sourced from generating facilities capable of operating on

Automatic Generation Control (“AGC”). Seller shall be responsible for all costs to

make the unit capable to respond to the Company’s AGC signals. For PPAs, the

Company shall have the right, but not the obligation, to dispatch the facility in the AGC

mode. For PPA proposals involving facilities that are not connected to the Southern

Company transmission system, bidders should verify dynamic transfer capability and

protocols with the Southern Company transmission system to ensure proper telemetry

PUBLIC VERSION

7

communications per the Southern Company Open Access Transmission Tariff

(“OATT”).

Run Time Requirements

Combined cycle (“CC”) resources must have a minimum down time of no more than 8

hours, and combustion turbine (“CT”) resources must have a minimum down time of

no more than 4 hours (although a minimum down time of no more than 1 hour is

preferred).

Quick Start Capability (for CTs)

For proposals reflecting CT resources, the Company requires quick start capability (i.e.,

10 minutes or less following notification from the Company operations personnel).

Demineralization/Environmental

The use of demineralized water supply for a resource should not limit the operations or

delivery of capacity and should be able to at least support 24 hours of full load

generation plus 10 hours of full pressure generation (if applicable).

Fuel Plan

Fuel Evaluation for Proposals

Natural Gas prices will be linked to a single monthly forecast of gas prices at a

common point (Henry Hub). Delivered gas prices will include the effect of

applicable gas transportation charges, fuel retention rates, historical basis

differentials and taxes. The requirement to purchase firm gas transportation and

storage will be applied as follows for evaluation purposes.

• CC units will be evaluated with sufficient firm gas transportation to allow

24 hours of operation at full load and 10 hours operation at peaking or

secondary modes of operation. CC units will also be evaluated with 13 days

of gas storage capacity based on firm gas transportation capacity. Some

reduction in gas storage capacity may be given to CC units with fuel oil

storage; however, fuel oil inventory costs will be applied.

• Simple cycle units without sufficient oil backup will require eight (8) hours

of firm gas transportation year-round. Simple cycle units with sufficient oil

backup will not require firm gas transportation provided it can burn oil year-

round. Simple cycle units with sufficient oil backup that cannot burn oil in

the summer months will require eight (8) hours of firm gas transportation

during the summer months. Gas storage is not required for simple cycle

PUBLIC VERSION

8

units, but fuel oil backup is strongly encouraged. Fuel oil inventory costs

will be applied as appropriate.

Fuel Oil Evaluation for Proposals

The Company prefers fuel oil availability for both CC and CT proposals. The

supporting facilities (including infrastructure and property interests) and operation

for onsite fuel oil storage will be expected to comply with the following standards,

including both tolling and non-tolling proposals for PPAs:

• For CC facilities, sufficient fuel oil storage capacity and reliable

replenishment capability to operate the generating facility for five (5)

continuous days per week for two (2) consecutive weeks at sixteen (16)

hours per day at full load.

• For CT facilities, sufficient fuel oil storage capacity and reliable

replenishment capability to operate the generating facility for five (5)

continuous days per week for two (2) consecutive weeks at eight (8) hours

per day at full load.

• If a bidder cannot meet the storage and replenishment capabilities outlined

above, the bidder should indicate its storage and replenishment capabilities

and the Company will evaluate this as a qualitative, non-price factor. For

PPA proposals, the parties will develop the additional requirements and

objectives necessary to implement the foregoing standards as a part of the

PPA.

Power Purchase Agreement Proposals

For purposes of this RFP, the Company is interested in PPA bid proposals based upon

“tolling” principles for five (5), ten (10), fifteen (15) and twenty (20) year terms from a

dedicated (first-call) generating resource (the “Facility”). The only PPA product that will

be acceptable is a 100% capacity and energy entitlement from one or more dedicated

generating units. Capacity offered under a PPA proposal will have the most value if fully

dispatchable and available year-round for first-call twenty-four (24) hours per day and

seven (7) days per week for the contracted period. PPA bid proposal prices must include

all costs that the bidder expects the Company to pay for the capacity and energy proposed,

including any ancillary services, such as reactive power, frequency response, etc. The

Company will not be responsible for any other costs associated with the project, including

but not limited to, station service, test energy, fuel for testing, rail spur construction, fuel

handling facilities, transmission system interconnection and all costs incurred necessary to

accomplish synchronization. On-site fuel storage or dual-fuel capability is not required, but

the non-price factor contribution of such characteristics will be considered. For proposals

offering multiple units in a single bid proposal, the bidder should indicate whether each

unit may be selected separately by the Company at the $/kW bid capacity price and with

PUBLIC VERSION

9

the other pricing components proposed for the entire bid. If a bidder desires to not offer

such unit combinations, the bidder should clearly state so in the bid proposal. If the bidder

desires to offer a different pricing structure for such unit combinations, the bidder must

specifically identify this pricing in its proposal.

Delivery of Energy

At all times during the PPA term, the delivery point must be at an available interface

into or within the Southern Company transmission system and capable of being

designated as a firm network resource as defined under the OATT. For each

project, the Company will determine the facilities and upgrades (and associated

costs) needed beyond the point of delivery. Such costs will be considered in the

Company’s evaluation. In addition to evaluating facilities and upgrades required

for interconnection, an important consideration in the evaluation of proposals will

be whether there is adequate transmission to deliver the energy of a proposed

project from the proposed point of interconnection to the Company and its

customers on a reliable basis. The costs of any modifications to the transmission

system to reliably deliver energy to the Company and its customers will be taken

into account in the evaluation. The Company will not be responsible for any

delivery charges or any costs (e.g., congestion) at or before the point of delivery.

Delivery of energy to meet the Company’s schedules must be from the Facility

identified in a bidder’s PPA proposal in response to this RFP. If a bidder expects

its Facility will not be available per the Company specified deadline, the bidder

may propose an interim resource, which can be in the form of a physical unit

provided that the physical interim resource is clearly identified and committed.

The Company will only allow interim resources with a megawatt capacity that is

within the range of ten percent (10%) or less to five percent (5%) more than the

megawatt capacity of the primary Facility; provided, however, that the period of

time a bidder uses an interim resource to fulfill such capacity need may not exceed

one (1) year for a five (5) year or ten (10) year PPA term and two (2) years for a

fifteen (15) year or twenty (20) year PPA term. In the case of a multiple resource

proposal, there must be no change proposed in the amount of capacity offered over

the term of the PPA beyond that described above, and all requirements of this RFP

shall apply equally to both the primary and interim resources. Also, appropriate

adjustments to the Pro Forma PPA will be made (e.g., the date when permits must

be obtained for the primary Facility).

Firmness of Proposed Resources

To be considered responsive, PPA proposals, including interim PPA resources,

bidders are required to provide the proposed capacity and energy to the Company

from specific, dedicated generating unit(s) on an unencumbered first-call basis and

priority. In the event a resource is not directly connected to the Southern Company

PUBLIC VERSION

10

transmission system at any time during the term of the PPA, the bidder must secure

firm transmission service from the source to the Southern Company transmission

system, with roll-over rights.

In the event a bidder intends to supply the capacity offered in its bid proposal

through purchase(s) from a third party, such bid proposal must demonstrate that the

generation source for the bidder’s purchase(s) will provide the Company with the

same unencumbered first-call firmness discussed above as if the bidder owned such

generating resources. In addition, appropriate provisions will be added to the Pro

Forma PPA to ensure adequate protection of the Company.

Interconnection and Transmission Requirements (Projects connected to the

Southern Company Transmission System)

1. The costs and benefits of any network transmission system modifications to

the Southern Company transmission system that are required to reliably

incorporate the proposed resource into the transmission grid will be

considered in the evaluation. Southern Company Services, Inc., acting as

agent for the Company, will conduct transmission impact studies, as

appropriate, to determine an estimate of such costs and benefits for

inclusion in the bid evaluation.

2. Each PPA bidder should propose the discrete point of electrical

interconnection for its project, which will define the point where the

generator interconnection facilities connect to the existing transmission

system. In proposing the point of interconnection, the bidder will bear cost

responsibility for all generation and transmission interconnection facilities

from the bidder’s generating equipment to the proposed point of

interconnection.

a. The proposed point of electrical interconnection should be

consistent with the expected point of electrical interconnection that

would be established if the bidder was currently applying for formal

interconnection.

b. If the bidder’s Facility has an interconnection agreement in place or

has applied for a formal interconnection, the bidder should provide

a copy of the interconnection agreement or application and, in the

case of an application, a summary of the status (e.g., interconnection

granted, pending).

c. Each bidder must supply a one-line diagram of the electrical system

depicting the Facility’s generator(s), generator step-up

transformer(s), collector bus(ses), high voltage circuit breaker(s)

and connections to the transmission system. In addition, each bidder

must clearly mark the proposed point of interconnection on such

PUBLIC VERSION

11

one-line diagram and clearly indicate the line of demarcation (i.e.

the change of ownership) between the Facility and the transmission

provider’s facilities.

d. The Company may suggest a different point of interconnection point

(with respect to location and/or voltage) if this would result in more

favorable economic consideration of the bid proposal being

evaluated, or as may be required per Company interconnection

policy and business practices.

3. For the purpose of this RFP, PPA bidders shall be responsible for all

transmission interconnection costs from the generating equipment to the

bidder’s proposed point of interconnection in their bid proposal, as

described in paragraph 2 above. Successful bidders are responsible for all

costs they incur related to interconnection of their Facility to the Southern

Company transmission system in accordance with their interconnection

agreement. In addition, successful bidders will be responsible for any costs

for upgrades required to electric systems other than the Company’s

transmission system as a result of interconnection Affected System (as

defined in the OATT) improvements.

4. Successful PPA bidders will be required to have submitted a valid

interconnection request for study within one week of short list notification.

It is each bidder’s responsibility to contact the appropriate transmission

provider to obtain all relevant information regarding interconnection

requirements for their Facility.

5. Successful PPA bidders must demonstrate that they can reliably deliver

energy to the bidder’s proposed point of interconnection. The Company

will accept no risk of failure to so deliver.

6. The Company is seeking proposals for which firm network integration

transmission can be available to serve the Company’s loads by the

commencement and throughout the term of the PPA. The Company will

determine whether network integration capability exists and the likely cost

to maintain such status over the term of the PPA. Bidders may desire to

obtain additional information regarding the Southern Company

transmission system and capabilities by using Southern Company’s Open

Access Same Time Information System (“OASIS”) web site (located at

https://www.oasis.oati.com/SOCO).

PUBLIC VERSION

https://www.oasis.oati.com/SOCO


12

Transmission Requirements (Projects not connected to the Southern Company

Transmission System)

While the Company prefers proposals that are directly connected to the Southern

Company transmission system, PPA proposals for Facilities not connected to the

Southern Company transmission system will be considered. However, any bidder

proposing a Facility not connected to the Southern Company transmission system

must demonstrate that it has firm transmission service for the entire term of the PPA

to deliver the entire capacity and energy of the Facility to the interface with the

Southern Company transmission system. The PPA will include provisions that

require the successful bidder(s) to (a) acquire firm physical transmission rights, and

(b) guarantee physical delivery of the Company’s energy entitlement from the

Facility to the designated interface with the Southern Company transmission

system. The Company will bear no transmission price or congestion cost

responsibilities relative to any transmission service through or out of other

transmission systems or balancing authorities. The successful bidder will be

responsible for, and proposed prices must include, any costs associated with

satisfying the foregoing requirements.

Options to Mitigate Short-Term Transmission Constraints

The Company is seeking PPA proposals for which firm transmission service can be

available to serve the Company’s loads by the service commencement date and

throughout the term of the PPA. The Company recognizes that some proposals

could have value to customers but may have potential transmission constraints that

are either (i) limited in time, or (ii) could be cured or mitigated by reducing the

megawatt capacity of the Facility. In such event, the Company will consider

options to cure or mitigate such transmission constraints where (i) a transmission

cure cannot be effectuated prior to the required commercial operation date, or (ii)

the cost to cure the constraints would make the bid non-competitive. Such options

may include, but are not limited to, (i) reducing the capacity amount proposed for

a portion of or the entire term of the PPA, (ii) shortening the term of the PPA, (iii)

identifying an Alternate Resource or interim resource to supply the capacity and

energy during such constrained periods, (iv) providing financial settlement in the

form of replacement power cost, or (v) providing financial settlement in the form

of liquidated damages.

In determining the applicability of an option, the Company will consider the

reliability impacts of implementing the option as well as the value provided by the

bid as compared to other proposals. If the Company proposes an option to a bidder,

the bidder will not be allowed to change the fixed pricing (capacity and fixed O&M)

components. If the solution requires a reduction in the MW capacity of the Facility,

the bidder will be allowed to propose changes to the operational characteristics and

energy pricing commensurate with the reduction in Facility capacity offered.

PUBLIC VERSION

13

Interconnection Guidance

Proposed resources for a PPA will either (i) interconnect to the transmission system

of the Company or (ii) be deliverable to the Southern Company transmission system

on a firm basis.

Bidders are responsible for submitting requests to interconnect their generation

resources and to obtain all relevant information regarding the interconnection

process. General information about generator interconnections to the Company’s

transmission system (>40 kV) can be found on Southern Companies’ OASIS

website (https://www.oasis.oati.com/SOCO), under the Generator Interconnection

folder. If a bidder has a site-specific question about the interconnection process,

bidders may submit a pre-application report request, as described on Southern

Companies’ OASIS website (https://www.oasis.oati.com/SOCO), under the

Generator Interconnection/Small Generator Interconnection folder.

The submission of a proposal in response to this RFP does not constitute an

interconnection request. Interconnection requests must be submitted to the

Company pursuant to the applicable interconnection process. Additional costs

associated with submitting an interconnection request may apply. All such costs

are the bidder’s sole responsibility.

Bidders selected for the “short list” must promptly submit all required

interconnection requests, to the extent not already submitted, in order to remain

eligible for further consideration under this RFP. Allowing sufficient lead time for

study of an interconnection request (typically 12-15 months) and for construction

of the required interconnection facilities and upgrades (typically 24 months or

longer) is critical to meeting any target in-service date.

Each short list bidder shall provide all relevant information regarding the status of

its interconnection request(s), including the interconnection facilities that will be

required to interconnect the proposed resource and the costs to interconnect,

including any contingent facilities (e.g. prior-planned or prior-queued projects).

The Company shall be entitled to make inquiries from time-to-time to obtain such

information.

Each bidder proposing a PPA for a facility that is interconnected to the Company

transmission system will be required to enter into an interconnection agreement (to

the extent the resource would interconnect to the Company’s transmission system),

which carries a monthly administration fee of $5,000 and operations and

maintenance charges specific to each project. This monthly administration fee does

not vary with project size and is applicable to any bidder proposing a PPA for a

Facility interconnected to the Southern Company transmission system. These costs

should be considered in the bidder’s pricing. The Generator Interconnection

Agreement will also require the bidder to provide security for all interconnection

PUBLIC VERSION





14

costs (including interconnection upgrades, potential tax liability, and any

contingent facilities) until the project achieves full commercial operation.

In addition to facilities and upgrades required for interconnection on the Company’s

side of the interconnection facilities, an important consideration in the evaluation

of proposals will be whether there is adequate transmission capability to reliably

deliver the energy of a proposed project from the proposed point of interconnection

to the Company and its customers for their use. Therefore, the Company, or a

designated agent of the Company, will conduct assessments, as appropriate, to

determine the costs of any modifications to the transmission system that are

necessary to deliver energy from a proposed resource for them to be appropriately

considered in the bid evaluation. Also, any Affected System (as defined in the

OATT) improvements for interconnection and delivery may require further studies

and Affected System improvement agreements with other utilities.

Availability and Alternate Delivery

The Company will rely, in part, on the contracted power supplied by any selected

PPA bid to provide dependable and reliable electric service to meet the needs of its

customers. Accordingly, the Company will require stringent protection for the

Company and its customers against failures by the PPA bidder to deliver contracted

capacity and energy in accordance with the PPA. The Company expects that, with

the exception of scheduled outages and Force Majeure events, the Facility will be

available for dispatch at all times. If the Facility is unable to meet the Company’s

dispatch schedules, the seller will be responsible for reimbursing the Company for

its replacement power costs. However, in lieu of incurring such costs when the

Facility is unavailable, the bidder will have the option to meet dispatch schedules

with capacity and energy delivered from an alternate resource on a firm basis

subject to the alternate delivery provisions in the Pro Forma PPA.

Performance Security

Any PPA that the Company enters into must provide reasonable assurance that the

Company will be able to readily recover its actual damages in the event of any

default by the seller under a PPA. Accordingly, simultaneously with the execution

of the PPA and thereafter for the term of the PPA, the bidder shall provide and

maintain performance security in a form and amount acceptable to the Company in

order to secure bidder’s performance obligations. Such performance security may

be in the form of a letter of credit, parent guaranty from a creditworthy guarantor

acceptable to the Company, or other security acceptable to the Company. The

specific requirements for PPA security are set forth in the Pro Forma PPA. The

indicative PPA security “Exposure Risk” requirements are set forth below;

however, the Company may determine to increase these security amounts prior to

PPA execution, including after consultation with the APSC.

PUBLIC VERSION

15

5 Year Exposure Risk ($/kW)

Combine Cycle $ 285

Combustion Turbine $ 70

Environmental

All bidders will be responsible for compliance with federal, state and local

environmental laws and regulations including but not limited to regulated

environmental air pollutants and emissions that the Facility is subject to. Seller

should provide all permits that the Facility is subject to under federal, state, and local

environmental regulations as required by the Company for review. The Company

will not excuse the delivery of energy as a result of non-compliance with any permit

or environmental law or regulation at the Facility

The bidder shall provide the Company with the benefit of an appropriate pro rata

portion of all environmental allowances (if any) allocated to the Facility by any

governmental authority at no cost to seller. Such pro rata portion of environmental

allowances will be equal to the amount of capacity designated to the Company in

the PPA proposal. The Company will be responsible for required environmental

allowances exceeding the pro rata portion allocated to the Company by the bidder.

The specific requirements for PPA environmental requirements are set forth in the

Pro Forma PPA.

Energy Price

PPA bidders are encouraged to bid variable costs consistent with their actual realized

variable costs. The Company prefers guaranteed variable costs that closely

approximate actual unit cost and performance. If the bid variable components are

not consistent with design specifications of the Facility, the Company may request

that a bidder modify its proposal(s). This cost-based pricing approach should reflect,

but is not limited to, the following components:

▪ Variable O&M

▪ Start Cost

▪ Heat Rate

Fixed O&M Price

The Company prefers that fixed O&M cost should be included in the capacity price.

However, if a PPA bidder elects to have a fixed O&M price separate from the

PUBLIC VERSION

16

capacity price, the bid fixed O&M price should be consistent with the bidder’s

expected actual costs.

Operating Flexibility

Bidders proposing a CC may bid a Facility with 1-on-1 configuration, 2-on-1

configuration, or any other configuration as desired. Bidders of 2-on-1 configured

CC Facilities must offer operation in the 1-on-1 mode if technically feasible by

design. Operating in 1-on-1 mode entails the ability to operate a single CT, one

HRSG and the steam turbine while the second CT is shut off. Bidders of the Facility

must offer cycling from 2-on-1 mode of operation down to 1-on-1 mode and back

up to 2-on-1 mode if technically feasible by design.

Bidders of 2-on-1 configured CC Facilities should offer pricing for 1-on-1 mode of

operation based on the cost of operating in this mode. This should entail a start

charge that accurately represents the cost of starting the Facility in the 1-on-1 mode

and the cost of moving from 1-on-1 mode to 2-on-1 mode. Bidders should also

provide heat rate curves consistent with the actual cost of 1-on-1 mode of operation.

In the event a bidder proposes a resource with other operational capabilities, (e.g. 3-

on-1 configuration, power augmentation, full pressure), such bidder’s proposal must

offer the operational flexibility consistent with the Facility capabilities and pricing

based on the cost of providing such operational flexibility.

For PPA bids with multiple modes of operation, bidders must specify the guaranteed

nominal capacity of each mode and quote a single capacity bid price for the entire

output of the Facility and insert those capacities and that price into Attachment C:

RFP Bid Form. In the event during any contract year the capacities designated by

mode are different from their respective guaranteed nominal capabilities by mode,

the seller will be subject to remedies described in the Pro Forma PPA.

Fuel Plan for PPA Proposals

PPA Bidders must provide details regarding the fuel supply plan to the proposed

generation Facility they are proposing for a PPA. Any such proposal would have to

adhere to the fuel plan provisions provided above in the Operating Parameters and

Requirements section in this RFP document.

The Company prefers a fuel tolling arrangement (i.e., an arrangement in which the

Company as buyer is responsible for fuel supply and transportation). As an

alternative, the bidder may propose a non-tolling agreement.

PUBLIC VERSION

17

Tolling PPA Proposals

• With respect to resources for which the bidder does have a pre-existing fuel

transportation arrangement, the Company prefers an assignment of the pre-

existing fuel transportation arrangement. With respect to resources for

which the bidder does not have a pre-existing fuel transportation

arrangement, the Company prefers bidder provide a fuel transportation

proposal from the connecting interstate pipeline company. The Company

would anticipate receiving assignment of the proposal upon execution. The

bidder should provide specific data regarding the costs and rates that will be

assigned pursuant to the fuel transportation arrangement or any proposal

from the pipeline company. All such arrangements must comply with

applicable regulatory requirements, and the Company, at its sole discretion,

may choose to reject assignment and impute its own supply plan.

• The bidder must propose to assign a pre-existing fuel transportation

arrangement or propose a new transportation arrangement to the Company

for the term of the PPA or reasonably demonstrate that the Company could

secure a fuel transportation arrangement matching the PPA term.

• The Company will be responsible for delivering to the agreed-upon gas

delivery point sufficient quantities of natural gas necessary to generate

energy pursuant to the Company’s energy schedules. The Company shall

bear the risk of loss of natural gas until it is delivered to the delivery point.

The party responsible for causing any imbalances shall be responsible for

payment of any imbalance charges assessed by the pipeline operator.

Non-Tolling PPA Proposals

• In the case of resources for which a PPA bidder does have a pre-existing fuel

transportation arrangement and the bidder proposes a non-tolling fuel plan

in its bid, then the bidder must provide complete details (e.g., costs, rates,

term) of its fuel transportation arrangements and fuel plan with its proposal.

• A successful bidder that proposes a non-tolling fuel plan will not be excused

from a failure to meet the Company’s energy schedules as a result of the

inability to provide natural gas to the Facility unless such an event affects

dedicated firm transportation and constitutes a force majeure event under the

applicable pipeline tariff, or is the result of an operational flow order that is

not directed toward such bidder’s failure to comply with the applicable

pipeline tariff. Unless excused by the preceding sentence, such bidder shall

be responsible to reimburse the Company for its incremental replacement

power costs. The PPA will also contain provisions such that if the Company

has substantial concerns about the reliability of the Facility due to the fuel

plan, the Company shall have the right to take over the fuel supply to the

Facility.

PUBLIC VERSION

18

Additional Options for PPA Bidders

The Company anticipates that most PPA proposals will be able to conform to the

PPA product definition as described above. However, in the event a bidder needs

additional flexibility in order to conform to the PPA product definition or to improve

the value of a proposal offering given the bidder’s circumstances, the following

options will be considered by the Company:

1. Consolidated Bids

The Company will accept a consolidated bid submitted jointly by two

entities. The bid should be comparable to that submitted by a single entity

in all substantive respects. For example, a single bid must include a

consolidated performance security response and a clear indication of the

party responsible for development, construction, maintenance and

operations. For purposes of the relationship with the Company and for

bidding into the RFP, the bid will be treated as though it is from a single

entity. The Company retains the right to evaluate the bidder’s qualifications

to perform under the PPA. If the bid is selected, the Company will require

that prior to PPA execution the two entities form or designate a single entity,

such as an LLC or LLP, to serve as the counterparty.

2. Multiple Facilities Bids

The Company will accept a bid in which a bidder utilizes two

separate Facilities to develop a response for a five (5), ten (10), fifteen (15)

year, or twenty (20) year term proposal. For example, if a bidder only had

the right to capacity and energy of Facility A for 8 years, the options

available to the bidder would be as follows:

a) Bid a 5-year proposal from Facility A;

b) Bid a 10-year proposal comprised of 8 years of Facility A and

2 years of Facility B;

c) Bid a 15-year proposal comprised of 8 years of Facility A and

7 years of Facility B.

d) Bid a 20-year proposal comprised of 8 years of Facility A and

12 years of Facility B.

It would be acceptable for such bidder to submit all four proposals; provided,

however, that each Facility must be clearly identified and committed to the

contract for its portion of the full term, and the bid must include all pricing

information (e.g., capacity price, variable O&M, Heat Rate Guarantees, etc.)

required by the RFP for both Facilities.

PUBLIC VERSION

19

3. Term Extensions

The Company will accept bids that offer a Facility for a 5, 10, 15 or

20-year term and provides the Company an option to extend the agreement

for a specified additional term of one to five years. The pricing for the

additional term must be no higher in any contract year than the pricing for

the final contract year of the conforming term. The Company is not under

any obligation to execute the extension. This optionality will be a non-price

consideration in the evaluation.

4. Early Service Commencement Date

The Company will accept bids that provide the option to set an early

service commencement date (i.e., a point earlier than the service

commencement date of December 1, 2023, as defined in the Pro Forma

PPA), but no earlier than December 1, 2019. For proposals offering an early

service commencement date, bidders should include PPA pricing for each

year of the extension. The bidder’s proposal offering a service

commencement date as defined in the Pro Forma PPA will be evaluated

against all other proposals received in the RFP. If the bid is selected as a

winning proposal and the bidder is offering an early service commencement

date that provides additional value to customers, the parties would execute a

PPA with the early service commencement date. If it is determined that the

extension does not provide additional value, the parties would execute a PPA

with a service commencement date as defined in the Pro Forma PPA. The

bidder’s pricing information for this option is to be entered in Attachment C

in the tab entitled “Early Start Price.”

In the event a bidder desires to submit a bid utilizing one or more of the

aforementioned options, the bidder should clearly state in the bid(s) that such

option(s) is being offered and provide sufficient detail to support the bid. To the

extent practical, the bidder should utilize the applicable attachments to this RFP for

each Facility offered and provide supplemental information as necessary to

communicate the bid terms. For instance, a bidder utilizing the Multiple Facility

option would complete Attachments B, C, D, E, F, and G for each Facility and

indicate in the bid the periods in which each Facility is offered. The Company

reserves the right to request additional information necessary to consider and

evaluate the bid.

VIE and Finance Lease Considerations

Given the length of the terms that PPA proposals may cover in response to this

RFP, and the business structure a bidder may choose to adopt, accounting and tax

rules may require either (i) that a PPA be accounted for by the Company as a

PUBLIC VERSION

20

Finance Lease3 or operating lease, or (ii) the seller under the PPA be consolidated

as a Variable Interest Entity4 onto the Company’s books. The Company is

unwilling to be subject to accounting or tax treatment that results from VIE

treatment. All proposals that are deemed likely to subject the Company to VIE

treatment will be rejected and considered a non-conforming bid. At PPA execution,

the chief financial officer of seller must provide certification that the Company will

not be subject to VIE treatment. Further, any PPA that the Company executes will

require that (i) seller covenant that the Company will not be subject to VIE

treatment at any point during the term of the PPA, and (ii) in the event that the PPA

causes the Company to be subject to VIE treatment at any point during the term of

the PPA, unless cured, such treatment will constitute a seller event of default under

the PPA. As provided in the Default and Remedies section of the Pro Forma PPA,

the Company would have the right to declare such event of default and cause early

termination of the PPA. If the seller is unable to clearly demonstrate that the

consolidation event was not due to the direct or indirect actions of the seller, the

seller will be liable for damages pursuant to the relevant provisions of the PPA.

Due to the expectation of changing guidance and standards in 2019, there will not

be a Finance Lease certification in the RFP. However, for evaluation purposes all

PPA bidders must represent whether their proposal qualifies as a Finance Lease,

based on their personal consideration of the factual matters and their understanding

of accounting standards regarding Finance Leases. If the bidder determines that the

proposal constitutes a Finance Lease, the bidder must also provide with such bid

the amounts that the Company would be expected to capitalize as a result of the

PPA. In any case for which the bidder determines the proposal is not a Finance

Lease, the bidder is required to provide supporting information sufficient to enable

the Company to independently verify that Finance Lease treatment will not

occur. The chief financial officer of seller or an officer having responsibilities for

financial accounting matters associated with the PPA shall provide the necessary

certification at PPA execution. For proposals declared as Finance Leases, the bid

evaluation will include the cost to the utility resulting from capitalization of PPA

costs on the Company’s balance sheet.

Furthermore, each bidder with a proposal selected for the short list of proposals for

further evaluation must also agree to make available any and all financial and

business data associated with the seller, the Facility and the PPA that the Company

would need to independently make its accounting determinations. Such

information may include, but may not be limited to, data supporting the economic

life, the fair value, investment tax credits associated with or other costs associated

with the Facility including debt specific to the asset proposed. Financial data

3 “Finance Lease” shall have the meaning as set forth in the Accounting Standards Codification (“ASC”)

Topic 842, Leases, as issued and amended from time to time by the Financial Accounting Standards Board. 4 “Variable Interest Entity” or “VIE” - shall have the meaning as set forth in ASC Topic 810, Consolidation,

as issued and amended from time to time by the Financial Accounting Standards Board.

PUBLIC VERSION

21

contained in the bidders’ financial statements (e.g., income statements, balance

sheets, etc.) may also be required.

Bidder’s Qualification Screen and Project Development Requirements

In the event a PPA bid proposing to develop a new project is identified by the

Company as one of the most competitive bids, the bidder will be required to submit

within two (2) weeks of such selection a certification signed by an officer of the

bidder to the effect that the bidder has the ability to implement such project,

including a full description of all development activities completed or pending

including, without limitation, negotiations for partnership agreements, equipment

supplier agreements, financing, permitting, and design work. Note, however, that

the bidder must submit, at the time of the proposal, verification that the bidder’s

contractor(s) are properly licensed to perform such work in the State of Alabama.

The Company may require bidders to provide copies of such development

documentation as a condition of further evaluation of their proposal(s). It will be

the bidder’s sole responsibility to obtain any financing associated with the project

and any PPA entered into by the Company shall not be contingent upon the bidder

obtaining such financing.

Asset Purchase and Sale Agreement Proposals

As indicated above, the Company will consider purchasing existing generating assets as

well as new-build/transfer generation facilities (i.e., new facilities to be constructed that

will be acquired after substantial completion through a purchase transaction) that are in

commercial operation as of the specified delivery period (“APSA bids”). APSA bids will

be subject to the receipt of all required regulatory approvals. The bidder must offer 100%

ownership of the facility or the business entity owning the facility, including appurtenant

works and generation interconnection facilities, rather than just a unit(s) of the facility or

percentage ownership of the facility or the owning business entity. Proposed generation

facilities should have no major operational limitations that reduce their ability to run for

extended periods. The Company will consider the acquisition of a generation facility or

facilities owned by multiple owners provided that the owners submit a joint proposal where

full ownership of the facility or facilities is being offered. If an APSA bid makes the short

list of competitive proposals, the bidder may be asked by the Company to also submit an

offer to purchase the business entity that holds the generating asset, if such was not done

as part of the initial bid. In the evaluation process, the Company will give preference to

proposals that afford it flexibility to purchase either the generating asset or the generating

asset together with the business entity.

In the evaluation process, APSA bids will receive comparable treatment to PPA bids.

APSA bids must complete Attachments B, C, D, E, F, G, and H, which indicate the

information the Company must receive from the bidder in order to perform preliminary

evaluation and associated Phase 1 due diligence.

PUBLIC VERSION

22

The Company will only accept APSA proposals for generation facilities located inside the

state of Alabama and that either are interconnected or have the ability to interconnect to

the Southern Company transmission system. Any proposal for the sale of a generation

facility or facilities not interconnected to the Southern Company transmission system must

include additional interconnection costs in the bid proposal. APSA bids for new-

build/transfers should follow the “Interconnection Guidance” section under PPA proposals

in this document as it pertains to the facility needs for interconnection.

APSA bidders must provide an “all-in” price that includes all customary and reasonable

facilities necessary for the reliable operation of the offered asset, including transmission

interconnection, gas lateral, land and any other facilities (the “Asset Facility”). The Asset

Facility shall include but not be limited to the asset’s major equipment and all auxiliary

equipment and facilities necessary or used for the production, control, delivery, or

monitoring of electricity produced on the property, as well as the appropriate rights to the

land. All equipment and other facilities installed on the bidder’s side of the transmission

interconnection point and the primary gas delivery point shall be considered a part of the

Asset Facility. The proposed prices must include all costs associated with the project up

to the point where the project facilities will connect to the interconnection facilities to be

constructed and owned by the Company including but not limited to engineering,

construction, equipment, insurance, and land. Each project must comply with all the

applicable federal, state, and local laws and regulations. All federal, state, and local

approvals, permits, licenses, and environmental regulations and associated fees or other

costs are the responsibility of the bidder. This includes any rezoning, land-use permits,

and other discretionary approvals that may be required by the local, state, or federal

governments. All data provided in Attachment C: RFP Bid Forms including capacity, heat

rate, O&M costs, startup fuel, and availability for the Asset Facility, must be based on

testing, past performance and good faith estimates, as applicable. Bidders should expect

the Company to conduct all due diligence assessments deemed necessary, in its sole

judgment and discretion, for short-listed APSA proposals to determine cost estimates to

own and operate the Asset Facility.

If a bidder proposing an APSA for a new-build/transfer generation facility is a winning bid

of competitive proposals, the bidder will be asked by the Company to submit monthly

progress reports of construction, meet the project milestones proposed by the Company in

the APSA, and may be subject to delay damages if the project does not achieve the

commercial operation date by the specified delivery date.

Fuel Supply for APSA

Bidders must provide details regarding the existing fuel supply to the proposed

generation facility, as well as a description of anticipated fuel supply agreements in

the future. Any such proposal would have to adhere to the fuel plan provisions

provided above in the Operating Parameters and Requirements section of this RFP

document.

PUBLIC VERSION

23

Environmental and Land Information for APSA

All bidder’s facilities should be in compliance with federal, state and local

environmental regulations including but not limited to regulated environmental air

pollutants and emissions that the facility is subject to. The bidder should provide

all permits that the facility is subject to under federal, state, and local environmental

regulations as well as any historical environmental and land citations against the

facility as required by the Company for review.

A legal description of the land being used for the project must be included in the

bid in addition to supporting documents to describe the nature of the possession of

the real property at the time of construction as either fee simple ownership or lease

(e.g., copy of option contract; copy of deed; copy of lease agreement). All

documentation that is currently available for the real property must be provided in

Attachment C under the tab “Land Information” (e.g., Title insurance /

Commitment, Title Abstract, ALTA Survey, Boundary and/or Topographic Survey,

Phase 1 Environmental Assessment, Wetland delineations, Threatened &

Endangered Species report, Land Patent and Geotechnical Analysis). Any of the

above documentation that becomes available at a later date should be supplied at

that time. The bidder should include detail information regarding site control of

the land.

Due Diligence Assessment for APSA

A short-listed APSA bidder should be prepared to provide, within fifteen (15) days

of being so notified, all necessary information to facilitate the performance by the

Company of a full Phase 2 due diligence assessment. Much of this data must be

made readily available electronically or in a data room setting to be copied and

reviewed by the Company. Also, additional data may be required depending on an

initial review of the provided information.

• APSA bidders (both existing and new-build/transfer proposals) must submit

a preliminary Phase 1 due diligence evaluation fee of $5,000 in addition to

the required bidders fee of $10,000 by the RFP deadline of November 9,

2018 by 5:00 pm CST.

• Any APSA proposal for an existing generating facility that is deemed

competitive and short-listed after the preliminary Phase 1 due diligence

evaluation must submit a Phase 2 due diligence evaluation fee of $250,000

within fifteen (15) days of being so notified. Bidders should refer to

Attachment H: Bidder Fees and Due Diligence Fees for more guidance on

due diligence fees.

PUBLIC VERSION

24

• Any APSA proposal for a new-build/transfer generating facility that is

deemed competitive and short-listed after the preliminary Phase 1 due

diligence evaluation must submit a Phase 2 due diligence evaluation fee of

$400,000 within fifteen (15) days of being so notified. Bidders should refer

to Attachment H: Bidder Fees and Due Diligence Fees for more guidance on

due diligence fees.

• In addition to a review of all pertinent documentation associated with any

APSA bid, the Company’s due diligence assessment (for both existing and

new-build/transfer APSA proposals) will require on-site visits by a Company

team, including personnel from all Company areas required for an adequate

assessment of the proposed generation resource, including but not limited to

the following:

o Generation Project Development o Finance

o Accounting o Maintenance

o Operations o Legal

Notice of Intent to Bid (“NOI”) Submittal Process

1. All bidders must complete the forms listed below for their proposed bid type project

located in Attachment B: Notice of Intent to Bid “NOI” Forms on the RFP website,

www.alabamapower.com/our-company/how-we-operate/capacity-rfp.html.

For a PPA project

• NOI Form

• Bidder’s Questionnaire

• Confidentiality Agreement

• Contractor Compliance Background Certification Form

o Documentation supporting bidder’s credit quality and verification of

appropriate state contractor’s licenses (for new projects)

• Contact(s) for the RFP Process

For an APSA project

• NOI Form

• Bidder’s Questionnaire

• Confidentiality Agreement

• Contractor Compliance Background Certification Form

o Verification of appropriate state contractor’s licenses (for new-

build/transfer APSA projects)

• Contractor Statistical Data (Employee Modification Rate or EMR)

• Contact(s) for the RFP Process

2. If a bidder is submitting more than one proposal, one NOI form must be submitted

for each proposal. This includes every version of the same project that is being

PUBLIC VERSION



25

proposed. Only one submission of the other required forms is necessary for each

bidder unless the information on the other required forms varies among the project(s)

submitted.

3. Bidders must submit the NOI forms in order for the Company to send the electronic

payment information to the provided contacts for the bidder’s evaluation fee and due

diligence fees.

4. The required forms must be sent by 5:00 pm CDT on October 5, 2018 by emailing

them using the following email address: [email protected] and by

sending one hard copy of the required forms through registered mail, addressed as

follows:

Forecasting & Resource Planning

APC Capacity RFP

600 North 18th Street / 6N-0603


Emailed files CANNOT be received as a .ZIP file, be greater than 20MB in size,

or posted in a file sharing folder (e.g., DropBox® or Google Docs™).

Bid Evaluation

Bid proposals submitted pursuant to this RFP will be considered and evaluated together.

Such evaluation will include a review of transmission and ancillary service requirements,

as appropriate, to determine the total cost impacts. Please note that the Company may

revise its capacity need forecast to reduce, eliminate, or increase the amount of power

sought, or change the schedule for this RFP, at any point during the RFP process or

negotiations. Further, this RFP and the documents are subject to modification or

withdrawal at any time in the sole discretion of the Company.

Bidder Evaluation Fees; Multiple Bids

For each project submitted, there will be a nonrefundable bidder evaluation fee

(“Bid Fee”) of $10,000. Electronic payment for the bid evaluation fee is to be made

to Alabama Power Company.

The bid is not complete and will not be evaluated unless the appropriate Bid Fee

has been received by the RFP deadline of 5:00 pm CST on November 9, 2018.

Utilizing the guidance of the following paragraph, the Company shall determine in

its sole discretion whether a bidder’s proposals constitute one or more proposals for

purposes of assessing the foregoing fees.

Bidders may submit multiple bid proposals in response to this RFP. Bid proposals

for the same site and the same generation technology and size that are offered with

PUBLIC VERSION



26

options in the fuel plan and/or fixed cost components will be considered a single

bid proposal. In addition, bid proposals for the same site containing options in the

number of generating units offered or portions thereof will be considered a single

bid if the generation technology is the same and the operational parameters and

variable pricing are the same in all proposals. In the event a bidder submits separate

proposals that vary regarding certain critical parameters, including but not limited

to the site, output, electrical characteristics, and technology (e.g., CT, CC,

cogeneration, primary fuel), such bidder will be required to pay a Bid Fee of ten

thousand dollars ($10,000) for each such proposal.

Submission of PPA proposals for five (5), ten (10), fifteen (15) and twenty (20)

years with all performance and variable pricing characteristics remaining the same

shall be considered one bid.

A separate NOI form also must be submitted for each version of the project,

whether or not there is a separate Bid Fee.

For APSA proposals, bidders will also be required to submit all “due diligence

fees”, including both the preliminary Phase 1 due diligence fee and the Phase 2 due

diligence fee for short-listed APSA proposals. Further information is provided in

Attachment H: Bidders Fees and Due Diligence Fees

Company’s Reservation of Rights and Disclaimers

The Company reserves the right, without qualification and in its sole discretion, to reject

as non-responsive any bid proposals received for failure to meet any requirement of this

RFP. Any proposal that does not satisfy the requirements of this RFP may be considered

nonresponsive, and the Company reserves the right to reject any such proposal without

opportunity for correction or cure. By way of example and not by limitation, the following

shall constitute non-responsive bids: a bid proposal offering non-firm capacity, a demand-

side bid proposal, an uncured, incomplete or non-specific bid proposal or a bid proposal

that fails to materially comply with the provisions of the Pro Forma PPA. The Company

also reserves the right to contact any bidder for additional information or to cure a

deficiency in the proposal.

The Company further reserves the right without qualification and in its sole discretion to

decline to enter into a PPA or APSA with any bidder for any reason. Nothing in this RFP

or in the associated materials provided should be considered an offer or acceptance of terms

or conditions of a PPA, an APSA, an interconnection agreement, or any other contract or

business arrangement. The Company shall have no obligation or liability to any bidder

unless and until an agreement with such bidder has been successfully negotiated, fully

executed, and all conditions to the effectiveness of such agreement are satisfied. The

Company reserves the right, in its sole discretion, to determine whether to pursue

negotiation and execution of any agreement with any bidder. Further, any agreement shall

PUBLIC VERSION

27

be subject to all requisite management approvals of the Company as well as approval by

the APSC in a form suitable to the Company, in its sole and absolute discretion.

Each bidder who submits a proposal(s) in response to this RFP waives any and all right of

recourse against the Company, its parent, and any of their affiliates for either rejection of

the proposal or for failure to execute an agreement with the bidder for any reason or for

any modification or withdrawal of this RFP. The Bid Fees submitted by any bidder will

not be refunded (unless otherwise determined in the sole discretion of the Company) in the

case of any modification or withdrawal of this RFP, rejection of any bid proposal for non-

responsiveness or other reason, failure to execute a PPA, or failure to execute an APSA.

All costs related to each bidder’s preparation of a response to this RFP are the sole

responsibility of the bidder. The Company will not reimburse or be held responsible for

costs associated with any bidder’s proposal in response to this RFP.

A bidder’s submission of a proposal to the Company shall constitute that bidder’s

acknowledgement and acceptance of all the terms, conditions, and requirements of this

RFP. All proposals submitted shall become the exclusive property of the Company and

may be used by the Company for any reasonable purpose.

Proposals submitted pursuant to this RFP will be evaluated in whatever manner the

Company deems appropriate, including (but not limited to) on a like-kind basis against

each other (independent of technology type) and against other power supply options that

may be available to the Company. Such other power supply options may include

generation resources owned or developed by the Company, other generation resources

located in the service territories of the Company and its affiliates, and other proposals for

capacity that are provided to the Company outside of this RFP process. The Company is

under no obligation to select any project, nor is the Company limited to choosing from the

resources submitted in response to this RFP.

Tentative Solicitation Schedule

DATE EVENT

September 21, 2018 Solicitation Issued

October 5, 2018 NOI Deadline

November 9, 2018 Bid Proposals Deadline

May 29, 2019 Short List/ Reserve List Determination

Guidance to Bidders and Instructions for Completing Forms

1. Frequently Asked Questions (“FAQ”) will be posted to the RFP website

(www.alabamapower.com/our-company/how-we-operate/capacity-rfp.html) and

updated periodically with repetitive questions and responses.

PUBLIC VERSION



28

All bidders must complete and submit Attachment B: Notice of Intent to Bid “NOI”

Forms by the NOI deadline, October 5, 2018 by 5:00 p.m. CDT. Bidders must submit

the NOI forms in order for the Company to send the electronic payment information for

the bidder’s evaluation fee and due diligence fees to the provided RFP bidder contacts.

2. Each bidder must submit an electronic copy of bid proposals to

[email protected] and by sending one hard copy of the required

forms through registered mail, addressed as follows:


APC Capacity RFP



All bid proposals and fees must be received by 5:00 pm CDT on November 9, 2018.

Any bid proposal that does not contain all of the required information by 5:00 pm

CST on November 9, 2018 will be subject to rejection as non-responsive by the

Company.

Emailed files CANNOT be received as a .ZIP file, be greater than 20MB in size,

or posted in a file sharing folder (e.g., DropBox® or Google Docs™).

3. Each bidder must submit a hard copy of the original bid signed by an officer (i.e.,

president, vice president, etc.) of the bidding company. The signed hard copy of the

original bid proposal should be submitted in a three-ring binder with transparent

pockets on the front cover and the spine mailed to:


APC Capacity RFP



4. In the event that a bidder discovers an error or omission in the bid after submitting

hard copies, the bidder must note any changes in the electronic copy and such

changes must be sent to [email protected] by 5:00 pm CDT on

November 9, 2018. In the event of a discrepancy between the electronic form and

the hardcopy form of the bids submitted, the electronic form will be considered to

be correct. In addition, one corrected hard copy must be received by the

Company within three business days of the filing deadline.

5. For each PPA bid, bidder must include a copy of the Pro Forma PPA (Attachment

G) with (i) all blank spaces completely filled in except those that are to be

completed by the Company, (ii) any and all proposed changes to the Pro Forma

PPA shown with specificity in a mark-up and accompanied by a summary of such

changes, including the specific identification of any changes to the PPA being

requested by a third party if the bidder is subject to a third party agreement, and

PUBLIC VERSION



29

(iii) a statement by the bidder that the terms and conditions of the applicable Pro

Forma PPA as proposed by the bidder are acceptable to the bidder.

6. A PPA bidder may submit a proposal sourced from a Facility owned by another

entity if the bidder has a contractual unencumbered first-call right to capacity and

energy from the Facility (e.g., a tolling agreement). The bidder must include the

modifications to the Pro Forma PPA necessary to conform the Pro Forma PPA to

that agreement. However, the Company will only accept changes that, when taken

as a whole, the Company determines do not materially affect the value to customers

and risk allocation inherent in the Pro Forma PPA. Such changes should be limited

to those specific to operations, scheduling and maintenance, including any

limitations on the Facility’s operations, inherent to the pre-existing agreement. The

bidder is encouraged to submit a redacted version of the pre-existing agreement

along with the Pro Forma PPA. However, the bidder is not required to submit such

agreement with the bid if the bidder provides a markup of the Pro Forma PPA

incorporating the provisions necessary to conform to the Pro Forma PPA. The

Company will require submission of such agreement if the proposal subsequently

is considered one of the more competitive proposals. The bid evaluation will

consider whether the bidder’s proposed changes can be accommodated, and if so,

will conduct a quantitative and qualitative evaluation of the impact of such

proposed changes. If the bidder’s proposed changes cannot be accommodated, the

bid may be rejected.

7. The concepts and material provisions of the Pro Forma PPAs are non-negotiable

except as provided in these instructions. Bidder’s proposals must conform to the

Pro Forma PPAs in all material respects except where (1) the bidder offers

provisions that the Company determines do not materially affect the value to

customers and risk allocation inherent in the Pro Forma PPA provisions, or (2) the

Pro Forma PPA assumptions do not conform to the specific characteristics of a

proposal. For example, if a bidder’s proposal conforms with the requirements of

the RFP and the bidder offers a fuel other than natural gas or a secondary fuel

supply, then the bidder may propose changes to the applicable Pro Forma PPA,

only to the extent needed, to conform a Pro Forma PPA’s provisions to such fuel

supply factors. The Company will consider the bidder’s proposed changes as part

of the evaluation of the proposal. The Company may propose its own changes to

conform the Pro Forma PPA to the bidder’s proposal and may discuss proposed

changes with the bidder before making a decision on the bidder’s proposal.

Depending on the type of proposal that a bidder is offering, more extensive changes

to the Pro Forma PPA may be needed. In accordance with these instructions, if the

bid is conditioned on any changes to the applicable Pro Forma PPA, then the bidder

must expressly so state and must provide the specific language changes that the

bidder proposes to the applicable Pro Forma PPA by red-lining the copy of the Pro

Forma PPA attached to the bid such that it shows the specific additions (bold and

underlined) and deletions (strike-through) that the bidder proposes.

PUBLIC VERSION

30

8. All rates for PPA bid proposals should be submitted with escalation rates at (1)

Actual GDPIPD/CPI (and will be evaluated based on projected GDPIPD/CPI) or

(2) a fixed, annual escalation rate that (a) does not exceed the projected cumulative

GDPIPD/CPI over the term of the agreement, (b) does not have any year with a

negative escalation rate, and (c) does not have any year with greater than four

percent (4%) escalation rate.

9. All energy prices must be quoted as dollars per megawatt-hour ($/MWh) (as

applied to variable operation and maintenance (“VOM”)) and as heat rates (as

applied to fuel cost), if applicable.

10. PPA bid proposal prices must include all costs that the bidder expects the Company

to pay for the capacity and energy proposed. The Company will not be responsible

for any other costs associated with the project, including but not limited to, station

service, test energy, fuel for testing, gas lateral construction, electrical

interconnection and all costs incurred necessary to accomplish synchronization.

Compliance with Laws; Regulatory Approvals

1. It shall be the complete and sole responsibility of the bidder to take all necessary

actions to satisfy any regulatory requirements, licenses and permits that may be

imposed on the bidder by any federal, state or local governmental authority

concerning the permitting, development, construction, operation, maintenance,

addition, renewal, retirement and disposal of the Facility, or concerning the

generation, sale and/or delivery of power. The Company will cooperate with the

successful bidder(s) to provide information or such other assistance, as may

reasonably be requested by a bidder to satisfy such regulatory requirements. The

bidder shall likewise provide such information and assistance to the Company in

connection with the Company’s regulatory approvals.

2. The Company must receive authorization from the APSC for approval of any PPA

or APSA entered into by the Company. Each agreement shall be conditioned on

the receipt of all requisite approvals, without material modification, from

governmental authorities (including the APSC).

Frequently Asked Questions (“FAQs”)

1. What types of generation projects will be considered? A project must be fully

dispatchable and available year-round, with an emphasis on availability in both the

summer (June-September) and winter (December-February) seasons. Energy storage

and any combination thereof is acceptable for this RFP as long as the operating

requirements specified in this document are met.

PUBLIC VERSION

31

2. Should I bid a solar facility in this firm capacity RFP or in the Renewable RFP? A

solar facility can be proposed in this Capacity RFP; however, it must be paired with

some type of energy storage or other type of generator and must be dispatchable, have

Automatic Generation Control (“AGC”), and meet other operating requirements, as

applicable, specified in this RFP document.

3. What size project can be proposed? Each project proposal, including an aggregate of

units at a facility, must be at least one hundred megawatts (100 MW) in total capacity

for the resource proposed and no single resource should exceed twelve hundred

megawatts (1,200 MW).

Example 1: If Facility A has two 70 MW units then a bidder must bid both units as a

complete resource for a total resource capacity of 140 MW.

Example 2: If Facility B has Unit 1 with a capacity rating of 1,300 MW and Unit 2 with

a capacity rating of 1,000 MW, only Unit 2 qualifies to be proposed in this RFP.

4. Where must projects be located? For Power Purchase Agreements (“PPAs”),

Alabama Power’s preference is that at all times during the PPA service term facilities

must be directly interconnected to the Southern Company transmission system (this is a

non-quantitative factor in the evaluation); however, for facilities not interconnected to

the Southern Company transmission system at any time during the service term must

obtain firm transmission service to the Southern Company transmission interface and

provide the name of the balancing authority area in which the project is located. For

Asset Purchase and Sales Agreements (“APSAs”), the project must be interconnected

or have the ability to interconnect to the Southern Company transmission system and

must be located in the state of Alabama.

5. When must the projects be operational? For PPAs, the service commencement date

should be December 1, 2023. However, an early service commencement date as early

as December 1, 2019 may be offered as a PPA option. For APSAs, existing facilities

may be acquired as early as November 1, 2019, subject to receipt of required regulatory

approvals. No proposal will be accepted with a commercial operation date after

December 1, 2023.

6. Is there a limit to the number of proposals one company can submit? No. There is

no limit on the number of proposals from an entity; however, separate bid evaluation

fees may be required for each proposal as described in the Capacity RFP document.

Regardless of the fee requirement, a separate “Notice of Intent to Bid” form must be

submitted for each proposal.

7. What is the Bidder's fee for a project submittal? For each project submitted, there

will be a nonrefundable bidder evaluation fee of $10,000. If the same project is being

submitted with a change to the business arrangement, the additional proposal must have

a separate bid evaluation fee of $10,000. However, if a PPA project is being proposed

PUBLIC VERSION

32

and there is only a contract term change (e.g., 5-year versus 20-year), no additional bid

evaluation fee is required.

Electronic payment for the bid evaluation fee is to be made to Alabama Power.

Bidders must submit the NOI forms in order for the Company to send the electronic

payment information for the bidder’s evaluation fee and due diligence fees to the

provided RFP bidder contacts.

The bid is not complete and will not be evaluated unless the appropriate bid evaluation

fee has been received by the RFP deadline of 5:00 pm CST on November 9, 2018.

8. When is the best time to submit an interconnection study request?

While an interconnection study request will not be required until a short list is

determined, there is a potentially long study time and construction lead time that could

impact the commercial operation date of a project. Information for submitting an

interconnection request is available to the bidders in the “Interconnection Guidance”

section under PPA proposals in the RFP document.

9. What should the price of the project include? The proposed project price (for PPAs,

and APSAs) should include the land and facilities associated with the project up to the

point of interconnection. This price should include all ongoing operation and

maintenance costs for the project facilities up to the point of interconnection, including

the monthly administration fee under the interconnection agreement (applicable to

bidders proposing a PPA with the Company) for the term of that agreement.

10. Will there be an opportunity later to change the price offered? Only as a result of

extraordinary circumstances as determined solely by the Company.

11. Will evaluation details such as avoided costs and proposal rankings be made

available? No. These items are considered confidential and will not be provided to the

bidders or to the public.

RFP Attachments Summary

All RFP attachments are available for bidders to download from the RFP website. This

RFP document and attachments with forms will be available on the RFP website until

November 9, 2018. Below is a summary of the attachments and their associated forms.

Attachment A: Non-Price and Other Qualitative Considerations

Attachment B: Notice of Intent to Bid (“NOI”) Forms

For a PPA

1. NOI Form

PUBLIC VERSION

33

2. Bidder’s Questionnaire

3. Confidentiality Agreement

4. Documentation Support

5. Contact(s) for RFP Process

For an APSA

1. NOI Form

2. Bidder’s Questionnaire

3. Confidentiality Agreement

4. Contractor Compliance Background Certification Form

5. Contractor Statistical Data (Employee Modification Rate or EMR)

6. Contact(s) for RFP Process

Attachment C: RFP Bid Forms

For a PPA

1. PPA Instructions

2. General Information

3. Operating Parameters

4. Fuel Supply Plan

5. PPA Pricing Summary

6. Generation Annual Monthly Info

7. Early Start Pricing

8. Land Information

For an APSA

1. General Information

2. Operating Parameters

3. Fuel Supply Plan

4. Land Information

5. APSA Bid Price

Attachment D: Interconnection Information Summary

Attachment E: Environmental Assessment Questionnaire

Attachment F: Stability Analysis Information

Attachment G: Pro Forma PPA

Attachment H: Bidder Fees and Due Diligence Fees

PUBLIC VERSION


Exhibit JBK-3

CONFIDENTIAL AND OMITTED

PUBLIC VERSION


Exhibit JBK-4


PUBLIC VERSION


Exhibit JBK-5


PUBLIC VERSION


Exhibit JBK-6


PUBLIC VERSION


Exhibit JBK-7


PUBLIC VERSION


Exhibit JBK-8


PUBLIC VERSION


Exhibit JBK-9


PUBLIC VERSION

1 | P a g e


ALABAMA POWER COMPANY ) PETITION ) Petitioner ) ) Docket No. ________

DIRECT TESTIMONY OF JEFFREY B. WEATHERS ON BEHALF OF ALABAMA POWER COMPANY

Q: PLEASE STATE YOUR NAME, POSITION AND BUSINESS ADDRESS. 1

A. My name is Jeffrey B. Weathers. I am the Manager of Resource Planning for Southern 2

Company Services, Inc. (“SCS”). My business address is 600 North 18th Street, 3

Birmingham, Alabama 35203. 4

Q: PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND. 5

A: I graduated from Auburn University in 1996 with a Bachelor of Science in Mechanical 6

Engineering, and in 1998 with a Master of Business Administration degree. I began my 7

career at Southern Company in 1998 at Plant Farley and joined SCS in 1999. Over the 8

next seven years, I progressed through roles of increasing responsibility in System 9

Planning, Fleet Operations, Asset Management, and Southern Power Generation 10

Development. I became the Energy Analysis Manager in 2006 with responsibility for 11

analyzing wholesale contracts, trading, and pool transactions. In 2011, I became 12

Manager of Financial and Contract Services, with responsibility for the wholesale billing, 13

settlement, and analysis of the Intercompany Interchange Contract (“IIC”), the wholesale 14

contracts of the operating companies, and the Open Access Transmission Tariff. In 15

December 2015, I moved into the role of Strategic Generation Planning Manager, with 16

responsibility over energy budgeting, scenario planning and forecasting, and asset 17

2 | P a g e

valuations. In September 2016, I was named Resource Planning Manager and assumed 1

additional responsibilities related to the coordinated planning process. 2

Q: DESCRIBE YOUR PROFESSIONAL RESPONSIBILITIES AS MANAGER OF 3

RESOURCE PLANNING. 4

A: My responsibilities generally include system integrated resource planning, energy 5

budgeting, system reliability and reserve margin analysis, support for Requests for 6

Proposals and other capacity procurement efforts, scenario planning and forecasting, and 7

production cost modeling and analysis. 8


A: Alabama Power has petitioned the Alabama Public Service Commission (“APSC”) for a 10

certificate of convenience and necessity, by which the Company would be granted the 11

authority to acquire certain rights and assume certain obligations relating to several 12

generation resources. As reflected in the testimony of Mr. Kelley, the IRP results shown 13

for Alabama Power, coupled with other factors impacting reliable long-term supply, 14

demonstrate a need for the Company to add approximately 2,400 MW of additional 15

resources by the 2023-2024 timeframe. The purpose of my testimony is to explain in 16

further detail the process used to establish the Target Reserve Margins reflected in the 17

IRP, which are an important part of the process used to determine Alabama Power’s 18

indicated need over the stated time horizon. By satisfying this need, Alabama Power will 19

have adequate resources to reliably serve its customers. 20

Q. WHAT IS “RESOURCE ADEQUACY”? 21

A. Resource adequacy is the process by which a utility determines the appropriate level of 22

resources to maintain reliability on its system. Accepted utility practice requires that 23

3 | P a g e

electric utilities maintain a sufficient amount of supply- and demand-side resources to 1

adequately serve the electricity needs of its customers. Alabama Power regularly 2

evaluates resource adequacy through its assessment of system resources, forecasting of 3

peak demand, and determination of appropriate reserve margins. 4

Q. WHAT IS THE RESERVE MARGIN AND WHAT IS ITS PURPOSE? 5

A. The reserve margin is the difference between the Company’s total existing and 6

committed capacity, including the impact of demand response programs, and the 7

Company’s projected peak demand. The reserve margin is generally expressed as the 8

percentage of existing and committed capacity above the projected weather-normal peak 9

demand (e.g., a reserve margin of 16.25 percent means that capacity resources are 16.25 10

percent above the projected weather-normal peak demand). In accordance with accepted 11

utility practice, Alabama Power maintains capacity reserves greater than the Company’s 12

projected peak demand in order to achieve the desired level of reliability in light of 13

various risk factors (such as weather, economic growth uncertainty, generator unit 14

performance, and market availability risk) that could cause the actual peak demand, or 15

generation available to meet the peak demand, to differ from projections. 16

Q. WHAT IS THE TARGET RESERVE MARGIN? 17

A. The Target Reserve Margin is the reserve margin that the Company uses for reliability 18

planning purposes. The actual reserve margin will vary over time due to variations in the 19

actual peak demand and resource availability, among other things. In contrast, the Target 20

Reserve Margin remains fixed (until updated on the basis of a Reserve Margin Study) and 21

is used to guide the Company’s resource planning decisions. The Company evaluates 22

three components in determining the Target Reserve Margin: economics, risk tolerance 23

4 | P a g e

and reliability. The Target Reserve Margin is set at a level that will minimize the 1

combined expected costs of maintaining reserve capacity, production costs, and customer 2

costs associated with service interruptions, while adjusting for risk and maintaining a 3

minimum level of reliability. 4

Q. HOW DOES THE COMPANY DETERMINE ITS TARGET RESERVE 5

MARGIN? 6

A. A Reserve Margin Study is conducted by SCS for the Southern Company system at least 7

every three years. The study identifies the Target Reserve Margin for the system 8

considering the costs and risks, as just described, to customers and the reliability of the 9

system. The target planning reserve margin for each of the retail operating companies is 10

then determined, taking into consideration the benefit of load diversity. A copy of the 11

2018 Reserve Margin Study, which is the most recent Reserve Margin Study for the 12

Company and the Southern Company system, is attached to my testimony as Exhibit 13

JBW-1. 14

Q. HOW DOES THE RESERVE MARGIN STUDY DIFFER FROM THE IRP 15

ANALYSES? 16

A. The Reserve Margin Study is similar to other analyses underlying the IRP, in that it uses 17

production cost techniques to simulate the operation of the system. However, unlike 18

other IRP analyses, which are based on weather-normal conditions, the Reserve Margin 19

Study evaluates the system under a broad set of system conditions, such as the impact of 20

economic uncertainty on loads as well as the impact of historical weather variations on 21

both loads and resources. 22

5 | P a g e

Q. WHY IS THE RESERVE MARGIN STUDY CONDUCTED AT A SYSTEM 1

LEVEL? 2

A. Because the Southern Company system is operated as a pool pursuant to the IIC, it is 3

appropriate to conduct the Reserve Margin Study at the system level. 4

Q. WHAT ARE THE TARGET RESERVE MARGINS USED IN ALABAMA 5

POWER’S 2019 IRP PROCESS? 6

A. The Company is taking steps to ensure that it can adapt its planning processes to meet the 7

changing demands of the system to reliably meet the energy needs of its customers for 8

the foreseeable future. To ensure proper reliability and economics, the Company 9

evaluates the required amount of resources needed above forecasted peak demand, or 10

reserve margin, to establish a Target Reserve Margin for the system for both the short-11

term and the long-term planning horizons. The Company is maintaining the current 12

16.25 percent long-term Target Reserve Margin for the summer for use in the summer 13

peak planning season. This Target Reserve Margin is calculated as it traditionally has 14

been, by comparing resources available in the summer – at their summer peak period 15

capacity – to the forecasted weather-normal summer peak load. Additionally, to address 16

winter reliability concerns, the Company has adopted a long-term Target Reserve Margin 17

of 26 percent for application to the winter peak planning season. This 26 percent reserve 18

margin is calculated based on winter peak period resource capacities and the forecasted 19

weather-normal winter peak load. For the short-term, the Company plans to increase the 20

Summer Target Reserve Margin from 14.75 percent to 15.75 percent, with a 21

commensurate short-term Winter Target Reserve Margin of 25.5 percent. As explained 22

6 | P a g e

in the Reserve Margin Study, the gap between the long-term and short-term periods 1

(regardless of season) has reduced from roughly 1.5 percent to 0.5 percent. 2

Q. WHY ARE DIFFERENT TARGET RESERVE MARGINS USED FOR SHORT- 3

AND LONG-TERM PLANNING? 4

A. Over the short-term (inside three years), there is typically less economic uncertainty and 5

therefore, a lower target planning reserve margin can be used for short-term planning 6

than is used for long-term planning. 7

Q. EXPLAIN WHY THE COMPANY IS ADOPTING SEASONAL PLANNING. 8

A. Historically, the Company’s capacity planning decisions have been driven by a 9

combination of summer peak loads and a corresponding summer-based Target Reserve 10

Margin. These planning techniques have proven to be successful in supporting reliability 11

while cost-effectively meeting the needs of customers in all seasons of the year. The 12

Company is not changing its summer-based Target Reserve Margin of 16.25 percent. 13

However, operational experiences, coupled with a review of historical data, forecasted 14

conditions, and other factors, indicate a significant shift in reliability risk from the 15

summer season to the winter season, thus requiring the Company to adapt its historically 16

summer-based capacity planning approach to specifically address these risks. Therefore, 17

the Company has adopted seasonal planning to address the winter reliability issue first 18

identified in the previous reserve margin study. Seasonal planning, with corresponding 19

seasonal target reserve margins, provides greater visibility into both summer and winter 20

capacity needs rather than limiting reliability decisions to a single season. 21

Q. DESCRIBE THE PRINCIPAL RISKS THAT CAUSED THE COMPANY TO 22

ADOPT SEASONAL PLANNING. 23

7 | P a g e

A. Prior to the 2014 Polar Vortex, the Southern Company system as a whole had 1

experienced an extended period of relatively mild winter weather. During that time, 2

however, the system was also undergoing significant changes in its peak loads and 3

generation resources. In addition, and as discussed in Mr. Kelley’s testimony, Alabama 4

Power itself had begun to experience weather normalized winter peak conditions that 5

exceeded its summer peak conditions. These changes, and particularly the 6

responsiveness of the system to cold weather, did not have the opportunity to manifest 7

themselves until the 2014 Polar Vortex and therefore had not previously been modeled in 8

any reliability studies. 9

Q: WHEN DID SOUTHERN COMPANY BEGIN A MORE FOCUSED ANALYSIS 10

OF THE EFFECTS OF CHANGING WINTER CONDITIONS ON RESOURCE 11

ADEQUACY? 12

A: The 2015 Reserve Margin Study was the first study that included assumptions and 13

modeling impacts to capture these changes and reflected a significant increase in winter 14

reliability risks. That study identified several underlying drivers, including: (1) 15

narrowing of the difference between summer and winter weather-normal peak loads; (2) 16

higher volatility of winter peak demands relative to summer peak demands; (3) cold-17

weather-related unit outages; (4) penetration of solar resources; and (5) increased fuel 18

transportation risk. 19

Q: WHY WAS SEASONAL PLANNING NOT ADOPTED AT THAT TIME? 20

A: At that point in time, the system’s experiences with changing winter conditions remained 21

relatively recent, and the consensus among the planning organizations was that an 22

8 | P a g e

increase in the summer Target Reserve Margin to 16.25 percent would serve to address 1

added reliability risks in the winter season. 2

Q: WHY DID THE 2018 RESERVE MARGIN STUDY MOVE TO SEASONAL 3

PLANNING? 4

A: The 2018 Reserve Margin Study not only re-identified the continued persistence of the 5

five risks enumerated above, but also identified a sixth driver associated with market 6

purchase availability under both extreme summer and winter conditions. Upon further 7

consideration and examination of these six reliability risks, the need for a broader 8

seasonal planning approach became evident. Specifically, given the risk of higher than 9

normal winter loads as well as differences in both availability and dependability of 10

resources in the summer and winter peak periods, it has become necessary to 11

independently evaluate resource adequacy in both the summer and winter peak periods to 12

ensure that system reliability has been adequately evaluated and addressed. 13

Q: HAS THE COMPANY UNDERTAKEN OTHER MEASURES TO ADDRESS 14

CHANGES IN WINTER CONDITIONS BEYOND ADOPTION OF A WINTER 15

TARGET RESERVE MARGIN? 16

A: Yes. The Company has taken operational and maintenance actions to help address the 17

concerns related to winter reliability risks. The Company has put in place measures to 18

mitigate risks from cold weather outages such as establishing a freeze protection 19

program, incorporating extreme weather scenarios into the winter operational readiness 20

assessments, and avoiding planned unit outages in January and February unless required 21

for environmental or other compliance-related reasons. The Reserve Margin Study 22

9 | P a g e

modeled expected improvements to historical plant performance associated with the 1

ability of the fleet to better withstand cold temperatures. 2

Q. WHY IS THE WINTER TARGET RESERVE MARGIN HIGHER THAN THE 3

SUMMER TARGET RESERVE MARGIN? 4

A. Numerically, the winter Target Reserve Margin is higher than the summer Target 5

Reserve Margin. This largely is a function of the reserve margin calculation (i.e., 6

resources less peak load, divided by peak load), as the forecasted system winter peak 7

loads are lower than the forecasted summer peak loads. 8

For every summer reserve margin there exists an equivalent winter reserve margin 9

that, for the same given system conditions, represents the same cost and reliability. In 10

fact, as explained in the 2018 Reserve Margin Study, the 26 percent long-term winter 11

Target Reserve Margin is consistent with the results of the 2015 Reserve Margin Study if 12

it had generated an equivalent winter Target Reserve Margin for the system. 13

Q: IS THE WINTER TARGET RESERVE MARGIN AN EXACT EQUIVALENT OF 14

THE SUMMER TARGET RESERVE MARGIN? 15

A: No. While this was the case in the 2015 Reserve Margin Study, the 26 percent winter 16

Target Reserve Margin in the 2018 Reserve Margin Study is 1.3 percent higher than the 17

winter equivalent of the 16.25 percent summer Target Reserve Margin, which is 24.7 18

percent. The additional 1.3 percent is needed to maintain the Company’s reliability 19

threshold and provides economic value for customers. This conclusion is supported by 20

the Company’s assessment, consistent with industry practice, that a minimum level of 21

system reliability should be a loss of load expectation (“LOLE”) of 0.1 days/year (often 22

referred to as a 1:10 – one in ten – LOLE Threshold). Figure V.1 in the Reserve Margin 23

10 | P a g e

Study shows that, if the 16.25 percent reserve margin is held in the summer, then 26 1

percent is needed in the winter for reliability to meet the 1:10 LOLE Threshold criteria. 2

The additional 1.3 percent also provides economic benefits for customers through 3

reduction in the risk of higher cost outcomes. 4

Q: DOES THE ADOPTION OF SEASONAL PLANNING CONSTITUTE A 5

CHANGE IN THE RESERVE MARGIN STUDY METHODOLOGY? 6

A: No. Other than adding an additional seasonal look, the Company has not changed its 7

reserve margin study methodology. The Reserve Margin Study continues to evaluate a 8

range of reserve margins to assess the following three criteria: (1) Total System Costs 9

(via the U-Curve); (2) Economic Risk (via the Value at Risk analysis); and (3) System 10

Reliability (via the LOLE evaluation). As described in the 2018 Reserve Margin Study, 11

three separate analyses were included: a traditional analysis; a winter focused analysis; 12

and a summer focused analysis. All three analyses were performed using the same 13

techniques employed in the 2012 Reserve Margin Study and 2015 Reserve Margin Study 14

except for the updated assumptions and minor methodological adjustments. For example, 15

the winter focused analysis used the same assumptions as the traditional analysis except 16

that load shapes were calibrated to the forecasted winter peak demand rather than the 17

forecasted summer peak demand. 18

Q. WHAT DOES THE ADOPTION OF SEASONAL PLANNING REVEAL AS TO 19

ALABAMA POWER’S RELIABILITY NEEDS? 20

A. As reflected in the Company’s IRP, and as discussed in the testimony of Mr. Kelley, 21

Alabama Power’s winter reserve margin is projected to be below both its diversified 22

long-term winter Target Reserve Margin (25.25 percent) and its diversified short-term 23

11 | P a g e

winter Target Reserve Margin (24.75 percent). Resolving the shortfalls in the winter 1

periods with resources available year-round will also resolve any shortfalls occurring 2

during corresponding summer periods. 3

Q: DOES THIS CONCLUDE YOUR TESTIMONY? 4

A: Yes. 5

Direct Testimony of Jeffery B. Weathers

Exhibit JBW-1

PUBLIC VERSION

An Economic and Reliability

Study

of the

Target Reserve Margin

for the

Southern Company System

January 2019

PUBLIC VERSION

i

EXECUTIVE SUMMARY

Electric utility customers expect and depend on high levels of service reliability. As such, a prudent

utility must have an economically balanced level of generating capacity that both exceeds the peak

load and that also meets a minimum reliability threshold. To have this reserve capacity available when

it is needed, a utility must plan beyond the upcoming season because the processes to procure

capacity, such as building a new unit or procuring a power purchase agreement (“PPA”), can take

several years to complete. The purpose of this Economic and Reliability Study of the Target Reserve

Margin (“Reserve Margin Study”) for the Southern Company System (“System”) is to determine the

amount of reserve capacity – or the Target Reserve Margin (“TRM”) – that should be maintained on

the System. The Reserve Margin Study includes the companies that participate in the Intercompany

Interchange Contract (“IIC”). Specifically, the Reserve Margin Study includes Alabama Power

Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and the

portion of Southern Power Company included in the IIC (collectively, the “Operating Companies”).

Although the TRM will be used to establish the long-term expansion plan, the 2018 Reserve Margin

Study should not be understood to determine one constant reliability index in perpetuity, but rather

should be re-evaluated on a periodic basis as the System evolves over time. The results of long-term,

constant reliability constraints can be impacted by projected changes in load shapes, unit costs, unit

availability, and other factors. The objective is to determine how these constraints affect the next

capacity decision, with subsequent re-evaluations modifying downstream decisions, as appropriate.

Traditionally, the TRM has been stated in terms of summer peak demands and summer capacity

ratings according to the following formula:

�� =�� − ��

�� 100%

Where:

TRM = Target Reserve Margin;



This traditional representation is essentially a Summer TRM and has been the only reserve margin

considered because the System (in aggregate) has always been and remains summer peaking on a

PUBLIC VERSION

ii

weather-normal basis. However, reserve margins can just as easily be stated in alternate terms.

Because of increased reliability risk and different capacity resources during the winter season (see

Appendix A), this report introduces and recommends the use of a Winter TRM in addition to the

traditional Summer TRM. The Winter TRM is stated and represented by the following formula:

�� =�� − ��

�� 100%

Where:




Because winter peak loads are different than summer peak loads (lower for a summer peaking utility)

and because winter generating capacity can have different operational characteristics than summer

generating capacity, the Winter TRM can be higher than the Summer TRM. For example, the final,

approved TRM from the 2015 Reserve Margin Study, which was essentially a Summer TRM,

represented an increase in TRM from 15% to 16.25% due primarily to winter reliability issues. If

planners had generated a Winter TRM from that study, the resulting reserve margin would have been

26%. However, such 26% Winter TRM would have represented both the same cost and the

same level of reliability as its 16.25% Summer TRM equivalent – despite the appearances of being

a “higher” reserve margin.

Reserve Margins are necessary because of uncertainties in operational conditions. The four primary

uncertainties causing this need are:

1) Weather: The System’s “weather-normal” load forecasts are based on average weather

conditions over the past 30+ years. If the weather is hotter than normal during warm seasons

or colder than normal during cold seasons, the load will be higher. The System’s peak demand

can be as much as 6.6% higher in a hot summer year and 22.0% higher in a cold winter year

PUBLIC VERSION

iii

than in an average year.1 Drought conditions and temperature-related impacts on unit outputs

can also significantly affect the System’s load and capacity balance.

2) Economic Growth: It is difficult to project exactly how many new customers a utility will have

or how much power existing customers will use from season to season. Based on historical

projections and actual economic growth, peak demand may grow by XXXX more than

expected over a four to five-year period.2

3) Unit Performance: While the Operating Companies have a tremendous track record in

keeping very low forced outage rates for the System, there have been occasions in the last

ten years when more than 10% of the capacity of the system has been in a forced outage state

concurrently.3

4) Market Availability Risk: The ability to obtain resources from the market when needed to

address a short-term System resource adequacy issue is uncertain. In general, having access

to resources in neighboring regions enhances a region’s reliability due to load and resource

diversity. However, the amount, cost, and deliverability of those resources are subject to the

external region’s resource-adequacy situation or transmission constraints at any given time.

While a region can expect some level of support from its neighbors, each region must carry

adequate reserves and manage its own reliability risks. Therefore, there is significant

uncertainty regarding the availability of such external support when it is most needed.

While each of these four factors creates a need for capacity reserves on its own, confluence of all

these risk factors poses considerable risk. Very high capacity reserves would be required to meet

customers’ load demands plus operating reserve requirements for all occurrences of such events.

However, maintaining such high levels of capacity reserves comes at significant expense and may

only eliminate very low probability events. A more appropriate approach to setting the TRM is to

minimize the combined expected costs of maintaining reserve capacity, System costs, and customer

costs associated with service interruptions, and adjust for the value at risk. A proper evaluation of

these costs will result in the Economic Optimum Reserve Margin (“EORM”), properly adjusted for risk.

However, that risk-adjusted EORM must also meet minimum reliability criteria thresholds. Common

practice in the industry regarding this minimum reliability criteria threshold is to plan for a Loss of Load

1 See Figure A.4 in Appendix A. 2 See Table I.3 in Section I. 3 See Figure I.6 in Section I.

PUBLIC VERSION

iv

Expectation (“LOLE”) of no greater than 0.1 days per year - or more commonly referred to in the

industry as a one event in ten years criterion (“1:10 LOLE”).

To understand and quantify the overlap of the four contributing factors to the need for reserve margins,

a system dispatch model, Strategic Energy and Risk Valuation Model (“SERVM”), is utilized. SERVM

evaluates the ability of the System’s capacity resources to meet load obligations every hour in a year

for thousands of combinations of weather, load forecast error, and unit performance scenarios. The

model quantifies, in dollar cost, two components of reliability-related costs. These components are:

1. Production Costs, including the cost of generation as well as the cost of purchases, and

2. Reliability Costs, including the cost of customer outages (i.e., expected unserved energy

(“EUE”) cost), emergency purchases, the cost of not meeting operating reserve requirements,

and non-firm outage costs (i.e., the cost of calling demand response resources).

The Production Costs and Reliability Costs, determined by the SERVM model, are then compared to

the Incremental Capacity Cost of new generation reserves. The analysis is performed on a range of

planning reserve margins from 10% - 20%. With lower reserve margin levels, the import costs and

Reliability Costs are high and vary widely, but the Incremental Capacity Cost and its associated

generation cost are low. At higher reserve margin levels, the import costs and Reliability Costs are

low, but the Incremental Capacity Cost and its associated generation cost are high. The objective of

this study is to find the reserve margin where the sum of these costs is minimized (i.e. the minimum

cost point), which is referred to as the EORM. The “U-curve” in Figure 1 shows the sum of Production

Costs, Reliability Costs, and Incremental Capacity Costs across the range of reserve margin levels

studied and demonstrates that the EORM occurs at a summer reserve margin of 15.25%. The figure

represents the weighted average costs over all the load, weather, and outage draws simulated and is

stated in terms of the traditional, summer-oriented reserve margin.4

4 That is, stated in terms of summer capacity ratings and summer weather-normal peak demand.

PUBLIC VERSION

v

Figure 1. Traditional EORM U-Curve

However, Appendix A discusses in detail the winter reliability risks facing the System. To address

those risks, the same analysis was performed from the perspective of a winter-oriented reserve

margin.5 The “U-Curve” in Figure 2 below shows the results of this analysis and demonstrates that

the Winter EORM is 22.5%. Although the winter EORM appears to be much higher than the summer

EORM, this difference is merely a function of how they were stated (i.e., stated in summer terms vs.

stated in winter terms as described above). The EORMs represent essentially the same level of cost

and reliability and are therefore essentially equivalent.

XXXXXXXXXXXXXXXXXXXXXXXXXXXXX

5 That is, stated in terms of winter capacity ratings and winter weather normal peak demand.

REDACTED

PUBLIC VERSION

vi

Figure 2. Winter EORM U-Curve

Finally, since winter is the driving factor behind the traditional results, thus leading to a need for a

Winter TRM, an analysis was performed to determine what a Summer TRM would be assuming

several of the key winter drivers were removed. Not all the winter-oriented drivers can be easily

removed from the analysis, but Figure 3 below shows a summer-focused U-Curve with incremental

cold weather outages and fuel constraints removed. The results of this analysis show that the EORM

for the Summer TRM when these key winter drivers are removed is 14%.

PUBLIC VERSION

vii

XXXXXXXXXXXXXXXXXXXXXXXXXXXXX

Figure 3. Summer EORM U-Curve

These three U-Curves and their associated analyses serve as the basis for determining a

recommendation for the Winter and Summer TRM. Since, as described in Appendix A, winter is the

constraining season for reliability on the System, the Winter TRM was considered first.

While the minimum cost of the winter U-Curve falls at 22.5%, the components that were evaluated to

develop the U-Curve all have substantially different risk characteristics. The fixed costs of procuring

capacity under a long-term PPA or building a new unit are relatively independent of the uncertainties

that affect reliability. On the other hand, Production Costs and Reliability Costs can both vary

significantly depending on weather, load forecast error, and unit performance.

The trade-off between static Incremental Capacity Costs and highly volatile Production Costs and

Reliability Costs is difficult to measure. The expected value of Production Costs and Reliability Costs

is the weighted average of all modeled simulations. For many mild weather or slow load growth

scenarios, these Production and Reliability costs will be lower than the expected outcome. However,

REDACTED

PUBLIC VERSION

viii

for more extreme cases, these Production and Reliability costs will be higher than the expected

outcome, but lower in probability of occurrence. The significantly higher costs from these cases

represent risk that should be considered when recommending a TRM because some of that risk may

be mitigated at low incremental cost. The approach taken to mitigate the risk of potential high cost

outcomes involves using a risk metric called Value at Risk (“VaR”). VaR is defined as the difference

in cost at the expected value and at some specified confidence interval (e.g., the 80th percentile of

risk). The VaR analysis looks at the incremental increase in expected cost to move from one reserve

margin to the next reserve margin and compares that with the incremental decrease in VaR. The point

at which the incremental increase in total system cost6 equals the incremental decrease in VaR

represents the EORM at that confidence interval (as opposed to the EORM at the weighted average).

This analysis was performed at various confidence intervals ranging from the 80th confidence interval

up to the 95th confidence interval using 0.25% reserve margin increments. As an example of the results

of this analysis, the 80th confidence interval resulted in an EORM of 26.0%,7 which represented an

increase in expected case system costs from the 22.5% TRM of XXXXXXXXXXX, but would reduce

VaR (i.e., exposure to higher than expected future outcomes) on the System by XXXXXXXXXXX.

This can be demonstrated graphically by developing the U-Curve at the 80th confidence interval

instead of the expected cost. Figure 5 below shows that if you draw the U-Curve at the 80th confidence

interval, the EORM is 26.0% instead of 22.5%. Therefore, a reserve margin a few percentage points

higher than the expected case EORM benefits customers by eliminating many of the more expensive

scenarios (thereby reducing the customers’ exposure to cost risk) without significantly increasing

expected costs. This outcome represents the risk-adjusted EORM at that confidence interval.

6 Production Cost plus Reliability Cost plus Incremental Capacity Cost.

7 Moving from 25.75% to 26.0% resulted in an incremental increase in weighted average costs roughly equal to the incremental decrease in VaR, while moving from 26.0% to 26.25% resulted in an increase in weighted costs that was greater than the decrease in VaR.

PUBLIC VERSION

ix

Figure 4. Summer EORM U-Curve

Figure 5. 80% Confidence Interval U-Curve (Winter)

Additionally, the Reserve Margin Study contains reliability metrics such as LOLE. Common practice

in the industry is to ensure that the TRM for planning purposes remains above an LOLE threshold of

0.1 days per year (or often referred to as a one in ten – 1:10 – year expectation of loss of load). LOLE

has always been considered as part of the reserve margin studies; but in previous studies, the 1:10

LOLE threshold was below the EORM. In the 2018 Reserve Margin Study, the 1:10 LOLE threshold

occurs above the EORM in both the summer and winter studies. It is not, however, greater than the

VaR80 result. Therefore, in the 2018 Reserve Margin Study, the 1:10 LOLE threshold must be given

greater consideration in the determination of the TRM than in previous studies. Figure 6 below shows

the relationship between LOLE and reserve margin for the winter-focused study. The figure shows

that the curve crosses the 1:10 LOLE threshold (i.e., an LOLE of 0.1 days per year) at XXXXXX reserve

margin. It is important that the TRM be above this 1:10 LOLE threshold to ensure an adequate level

of reliability on the System. Otherwise, customers may be exposed to potential outages due to

REDACTED

PUBLIC VERSION

x

generation shortfalls more frequently than in other regions of the country. Results are similar in the

traditional study.

XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX

Figure 6. LOLE as a Function of Winter Reserve Margin

The 2018 Reserve Margin Study recommends a long-term Winter TRM of 26% based on the following:

1. The TRM should be greater than the 25.25% 1:10 LOLE threshold to ensure an adequate level

of reliability on the System;

2. A reserve margin of 26% represents the risk-adjusted EORM at the 80th confidence interval

(the 80th percentile of risk – i.e., VaR80);

3. Compared to the 22.5% expected case EORM, a 26% risk-adjusted EORM reduces VaR at

the 80th confidence interval by XXXXXXXXXXX while only increasing expected cost by

XXXXXXXXXXXX;

4. Compared to the 25.25% 1:10 LOLE threshold, a 26% risk-adjusted EORM reduces VaR at

the 80th confidence interval by xxxxxxxxxx while only increasing expected cost by xxxxxxxxxxx;

and

REDACTED

PUBLIC VERSION

xi

5. A 26% Winter TRM is consistent with results from the 2015 Reserve Margin Study,8 confirming

the results of that study.

For the long-term Summer TRM, in addition to consideration of the VaR results, consideration must

also be given to the combined summer and winter LOLE. While the Summer-oriented U-Curve

indicated an EORM of 14%, the VaR85 calculation resulted in a reserve margin of 16.75%. Therefore,

a Summer TRM of up to 16.75% could be justified based on this case. However, LOLE must also be

considered. If resources added to the System are available in both the winter and the summer, the

LOLE will be in accordance to the curve in Figure 6. However, if the System’s winter requirements are

met with resources that are not available in summer, then a disconnect between the summer LOLE

and the winter LOLE occurs. Therefore, when the combined LOLE for both summer and winter are

considered, there is a floor for the Summer TRM that must be maintained to ensure that that the total

combined summer and winter LOLE does not fall below the 1:10 LOLE threshold (“Summer TRM

Floor”). Figure 7 below shows the 1:10 LOLE threshold Summer TRM Floor for various Winter TRM

values.

8 In the 2015 Reserve Margin Study, “An Economic Study of the System Planning Reserve Margin for the Southern Company System” (January 2016), the winter equivalent of the approved 16.25% TRM would have been 26%.

PUBLIC VERSION

xii

Xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx

Figure 7. Summer Target Reserve Margin Floor

xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx

xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx. Therefore, it is

recommended that the current, approved 16.25% TRM (which is already stated in summer terms)

remain in place as the Summer TRM.

For short-term planning (inside three years), a sensitivity has been performed which recognizes that

there is typically less economic uncertainty in the nearer term (1-3 years out) than in the longer term

(4 years out or greater). This sensitivity shows a difference in long-term reserve margin and short-term

reserve margin of 0.5% is appropriate.

These recommendations are designed to provide guidance for resource planning decisions but should

not be considered absolute targets. As explained throughout this report, various factors may justify

REDACTED

PUBLIC VERSION

xiii

decisions that result in reserve margins above or below the targets mentioned above such as the large

size of capacity additions, the availability and price of market capacity, or economic changes.

RECOMMENDATIONS:

1. Implement Seasonal Planning with a Summer TRM and Winter TRM 2. Maintain current approved TRM of 16.25% as the Summer TRM 3. Implement a Winter TRM of 26% 4. Apply a short-term reserve margin with a 0.5% differential from the long-term reserve

margins

PUBLIC VERSION

xiv

TABLE OF CONTENTS

EXECUTIVE SUMMARY ...................................................................................................... i

TABLE OF CONTENTS ........................................................................................................ xiv

LIST OF TABLES .................................................................................................................. xvii

LIST OF FIGURES................................................................................................................ xviii

I. ASSUMPTIONS ................................................................................................................. 1

Reliability Simulation Model ................................................................................. 1

Study Year............................................................................................................ 1

Weather Years ..................................................................................................... 1

Market Modeling .................................................................................................. 4

Load Forecast Uncertainty ................................................................................... 9

Generating Unit Capacity Ratings ........................................................................ 11

Generating Unit Outage Rates ............................................................................ 17

Incremental Cold Weather Outages .................................................................... 20

Planned Outage Patterns ...................................................................................... 21

Commitment and Operating Reserves ................................................................. 22

Dispatch Order ..................................................................................................... 23

Dispatchers’ Peak Load Estimate Error ............................................................... 24

System-Owned Conventional Hydro Generation ................................................ 25

SEPA Conventional Hydro ................................................................................... 27

Pumped Storage Hydro ....................................................................................... 28

Demand Response Resources ............................................................................ 28

Renewable Resources ........................................................................................ 29

Natural Gas Availability ........................................................................................ 29

Oil Availability ....................................................................................................... 31

Capacity Cost ....................................................................................................... 31

Cost of Expected Unserved Energy .................................................................... 31

II. SIMULATION PROCEDURE ............................................................................................ 33

A. Case Specification ............................................................................................... 33

B. Probabilities of Occurrence for Input Variables ................................................... 34

C. Reliability Model Simulations ............................................................................... 34

III. BASE CASE RESULTS ................................................................................................... 39

PUBLIC VERSION

xv

A. Traditional Study Results ..................................................................................... 39

B. Winter-Focused Reserve Margin Results ............................................................ 40

C. Summer-Focused Reserve Margin Results ........................................................ 42

D. Risk Analysis ........................................................................................................ 43

E. Loss of Load Expectation ..................................................................................... 48

F. Total System Cost Components .......................................................................... 51

IV. SENSITIVITY ANALYSES............................................................................................... 55

A. Capacity Price ...................................................................................................... 55

B. Minimal Cost of EUE ............................................................................................ 56

C. Publicly Available Cost of EUE ............................................................................ 56

D. No Cold Weather Outage Improvements ............................................................ 57

E. Higher Scarcity Price Curve ................................................................................. 57

F. 50% Reduced Transmission ................................................................................ 57

G. 50% Increased Transmission .............................................................................. 57

H. 50% Higher Base EFOR ...................................................................................... 58

I. 50% Lower Base EFOR ........................................................................................ 58

Summary of Sensitivity Analyses ............................................................................. 58

Short-Term Load Forecast Error .............................................................................. 59

V. CONCLUSION .................................................................................................................. 61

Winter Target Reserve Margin ................................................................................. 61

Summer Target Reserve Margin .............................................................................. 62

Appendix A – Examining the Need for a Winter Target Reserve Margin ............................. 1

A. Background .......................................................................................................... 1

B. Key Drivers ........................................................................................................... 4

B.1 Narrowing of Summer and Winter Weather-Normal Peak Loads ..................... 4

B.2 Distribution of Peak Loads Relative to the Norm ............................................... 5

B.3 Cold-Weather-Related Unit Outages ................................................................. 7

B.4 Penetration of Solar Resources ......................................................................... 9

B.5 Increased Reliance on Natural Gas ................................................................... 11

B.6 Market Purchase Availability .............................................................................. 15

C. Aggregate Impacts of Drivers on Winter Reliability ............................................. 16

C.1 Total Available Capacity by Season .................................................................. 16

C.2 EUE by Season .................................................................................................. 17

C.3 LOLE by Season ................................................................................................ 18

PUBLIC VERSION

xvi

D. The Nature of the Winter Reserve Margin ........................................................... 19

E. Resulting Need for Winter Target Reserve Margin (“TRM”) ................................ 22

F. Conclusion ............................................................................................................ 24

Appendix B – Capacity Worth Factors .................................................................................. 1

A. Background .......................................................................................................... 1

B. The SERVM Reliability Cost Report .................................................................... 1

C. Capacity Worth Factor Results ............................................................................ 3

PUBLIC VERSION

xvii

LIST OF TABLES

Report Tables

Table I.1. Simulation Regions Summary for Summer ........................................................................... 5

Table I.2. Simulation Regions Summary for Winter .............................................................................. 6

Table I.3. Load Forecast Error ............................................................................................................. 10

Table I.4. Nuclear, Coal, and Gas Steam Unit Ratings ....................................................................... 11

Table I.5. System CT Ratings .............................................................................................................. 13

Table I.6. System CC Ratings.............................................................................................................. 16

Table I.7. Steam Unit Sample Time to Failure and Time to Repair Data ............................................ 18

Table I.8. Approximate EFOR by Unit Class ....................................................................................... 19

Table I.9. Historical Dispatcher's Peak Load Forecast Error ............................................................... 24

Table I.10. EUE Cost ........................................................................................................................... 32

Table II.1. SERVM Case Variables ...................................................................................................... 33

Table II.2. Simulation Case Probability ................................................................................................ 34

Table II.3. Sample Calculation Top 10 Worst Reliability Costs at 17% Reserves .............................. 36

Table II.4. Worst Reliability Costs Weighted Probability ..................................................................... 36

Table II.5. Production Cost Components For Sample Data Set .......................................................... 37

Table II.6. Production Cost Weighted Probability ................................................................................ 37

Table III.1. Value at Risk ...................................................................................................................... 46

Table IV.1. Short-Term Load Forecast Error ....................................................................................... 60

Appendix A Tables

Table A. 1. Historical EFOR During Cold Weather Events .................................................................... 8

Appendix B Tables

Table B. 1 B2018 Vintage CWFT at 16.25% Summer TRM (Central Prevailing Time) ........................ 3

Table B. 2 B2018 Vintage CWFT at 26% Winter TRM (Central Prevailing Time) ................................ 4

PUBLIC VERSION

xviii

LIST OF FIGURES

Report Figures

Figure 1. Traditional EORM U-Curve ..................................................................................................... v

Figure 2. Winter EORM U-Curve .......................................................................................................... vi

Figure 3. Summer EORM U-Curve ...................................................................................................... vii

Figure 4. 80% Confidence Interval U-Curve (Winter) ........................................................................... ix

Figure 5. LOLE as a Function of Winter Reserve Margin...................................................................... x

Figure 6. Summer Target Reserve Margin Floor ................................................................................. xii

Figure I.1. Historical Low Winter Temperatures .................................................................................... 3

Figure I.2 Historical High Summer Temperatures ................................................................................. 4

Figure I.3. Simulation Topology ............................................................................................................. 7

Figure I.4. Scarcity Pricing Curve .......................................................................................................... 8

Figure I.5. Ambient Temperature Output Curves ................................................................................ 17

Figure I.6. Unplanned Outage Probability ........................................................................................... 20

Figure I.7. Cold Weather Outage Assumptions ................................................................................... 21

Figure I.8. Planned Outage Probability by Month ................................................................................ 22

Figure I.9. System Dispatch Stack ....................................................................................................... 24

Figure I.10. Hydro Energy Availability (1998 Example Data) .............................................................. 26

Figure I.11. Annual Scheduled Hydro Energies .................................................................................. 27

Figure I.12. Interruptible Gas Transportation Availability Model ......................................................... 30

Figure II.1 Variable Calculation Formula ............................................................................................. 35

Figure III.1. Traditional EORM U-Curve............................................................................................... 39

Figure III.2. Seasonal EUE by Reserve Margin ................................................................................... 41

Figure III.3. Winter EORM U-Curve ..................................................................................................... 42

Figure III.4. Summer EORM U-Curve (Without Key Winter Drivers) ................................................... 43

Figure III.5. Production and Reliability Cost Distributions for Winter Reserve Margins ...................... 44

Figure III.6. Top 10% Distribution for Winter Reserve Margins ........................................................... 45

Figure III.7 80% Confidence Interval U-Curve ..................................................................................... 48

Figure III.8. Loss of Load Expectation by Summer Reserve Margin ................................................... 49

Figure III.9 LOLE for Winter Reserve Margins .................................................................................... 50

Figure III.10. Incremental Capacity Cost (Winter Focus) .................................................................... 52

Figure III.11. Reliability Cost ................................................................................................................ 53

PUBLIC VERSION

xix

Figure III.12. Production Cost .............................................................................................................. 54

Figure IV.1. EORM as a Function of Capacity Price ........................................................................... 56

Figure IV.2. Summary of Winter Sensitivity Results ............................................................................ 59

Figure V.1. Minimum Acceptable Summer Target Reserve Margins .................................................. 62

Figure V.2. Economic Components of Winter TRM ............................................................................ 63

Figure V.3. Economic Components of Summer TRM ......................................................................... 64

Appendix A Figures

Figure A. 1. Summer and Winter Historical Peak Demands ................................................................ 1

Figure A. 2. Historical Minimum System Temperatures ........................................................................ 2

Figure A. 3. Historical Forecasted Weather Normal Peak Loads .......................................................... 5

Figure A. 4. Distribution of Modeled Summer and Winter Peak Loads ................................................. 6

Figure A. 5. Historical Summer and Winter Peak Loads ....................................................................... 7

Figure A. 6. Cold Weather Unit Outage Performance ........................................................................... 9

Figure A. 7. Solar Resource Penetration ............................................................................................. 10

Figure A. 8. Solar Output During Highest 20 Load Hours ................................................................... 11

Figure A. 9. Historical and Projected Energy Use by Fuel Type ......................................................... 12

Figure A. 10. Monthly Distribution of Operational Flow Orders ........................................................... 13

Figure A. 11. Interruptible Gas Transportation Model ......................................................................... 14

Figure A. 12. Historical Purchases During Cold Weather Events ....................................................... 15

Figure A. 13. Total Available Capacity by Temperature ...................................................................... 17

Figure A. 14. Seasonal EUE by Reserve Margin ................................................................................ 18

Figure A. 15. Seasonal LOLE by Reserve Margin .............................................................................. 19

Figure A. 16. Winter Equivalent Waterfall ............................................................................................ 22

Appendix B Figures

Figure B. 1 Treatment of Reliability Components in the CWFT Calculation ......................................... 2

PUBLIC VERSION

1

I. ASSUMPTIONS

The following sections of this report provide detailed discussions related to the input assumptions

associated with the 2018 Reserve Margin Study.

Reliability Simulation Model

SERVM was used to calculate Production Costs and Reliability Costs for determining the EORM.

These calculations were performed across a broad range of uncertainty risks in load forecast error,

weather, unit availability, and performance of non-dispatchable, renewable resources.

Operating events are selected from actual operating history to determine generating unit availability.

For each hour in every simulation, each unit will either be operating, on reserve shutdown, partially

failed, completely failed, or on scheduled maintenance. The total capacity online and available for

purchase is calculated and compared to the load to determine the associated EUE. Performing the

random unit status draws for 100 iterations for every hour in the dataset results in average or expected

case EUE.

SERVM perfectly matches load and generation, which is impossible to do in the real world. In actual

practice, load would be curtailed in large blocks and would be off longer than necessary. If this reality

could be incorporated into the model, the expected EUE would likely increase and the EORM would

increase. As such, the results of the 2018 Reserve Margin Study should be considered conservative.

Study Year

Xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx




xxxxxxxxxxxxxxxxxxxx. The representative year selected for this study was 2025.

Weather Years

The impact of weather on load was reflected by simulating the System using the 54 historical annual

weather patterns from 1962 through 2015. These 54 patterns were then used to develop annual load

shapes that would approximate what the load shape would be in the study year (2025) if the weather

PUBLIC VERSION

2

pattern matched that of one of the historical years. Two annual load shapes were developed for each

of the 54 weather patterns. One assumed the first day of the year occurred on a Tuesday; the other

assumed the first day of the year occurred on a Saturday. This was done to vary what day of the week

extreme weather conditions were assumed to occur, since extreme weather can theoretically fall either

on the weekend or on a peak day. These 108 datasets or “weather years” were given equal probability

of occurrence.

The weather year load shapes were developed by using a neural net model to establish the

relationship between the weather and load. The neural net was calibrated using weather and load data

for the years 2010 through 2015 so that more recent customer usage patterns are reflected. The

calibrated neural net was then used to construct the 108 weather year load shapes using the 54

historical weather patterns and two start days. The resulting loads are integrated hourly load shapes.

The temperature data used to develop these load shapes reflect the system weighted average

temperature of several locations around the System’s footprint. Figure I.1 and Figure I.2 show the

historical low winter and high summer temperatures experienced for the 54 weather years modeled.

PUBLIC VERSION

3

Figure I.1. Historical Low Winter Temperatures

PUBLIC VERSION

4

Figure I.2 Historical High Summer Temperatures

Market Modeling

The SERVM model allows the System to account for expected support from neighboring regions based

on historical load diversity and unit performance diversity. Each weather year modeled uses the actual

historical temperature and related load diversity for each region. The System is expected to be able

to buy power from neighboring regions that do not typically peak in the same hour as the System if

those neighboring regions have economic capacity available to purchase.

Resource adequacy planning requires modelers to build assumptions about the level of support

available from neighboring regions. The actual operation of each unit for every neighboring region is

modeled in the same way that resources are modeled within the System. Hydro, CTs, base load

thermal resources, renewables, and demand response resource (“DRRs”) are discretely modeled so

that an accurate hourly market price forecast is produced. The CTs that have been modeled as

PUBLIC VERSION

5

marginal units to the System for purposes of developing the U-Curves are used to avoid purchasing

from neighbors at high costs when they are either dispatching high cost resources or in scarcity

situations.

The neighboring regions used in the simulation are summarized in Table I.1 (for Summer) and Table

I.2 (for Winter) below. The reserve margins modeled in some regions were increased above their

published targets to ensure those regions have a reasonable level of reliability (approximately

equivalent to the 1:10 LOLE threshold). This is necessary since the regional model used in this

analysis does not model a neighboring region’s other interconnected regions (i.e., the 2nd tier from the

System) to account for the reliability benefit a neighboring region may obtain via purchases from its

own neighboring regions. Without the adjustment, the reliability of these regions would be understated

and would inappropriately underestimate the System’s access to external markets.

Table I.1. Simulation Regions Summary for Summer

9 Capacity Benefit Margin (“CBM”) is a firm import reservation on the transmission system for use during emergencies.

Region NameSummer Reserve Margin

Modeled (%)

Peak Load (MW)

Available Transfer Capability into

Southern Company Systems

(MW)

CBM9 into Southern Company Systems

(MW)

TVA xxx 29425 796 300Duke Energy Carolina xxx 20433 180 350

SCEG xxx 5736 148 0

Santee Cooper xxx 4288 360 50

FPL xxx 26145 20 100Duke Energy FL xxx 8796 18 50

JEA xxx 2579 6 100

Power South xxx 2139 300 -

OPC xxx 5962 Unlimited -

MEAG xxx 2476 Unlimited -

TAL xxx 632 3 -

MISO xxx 29014 1694 100

PUBLIC VERSION

6

Table I.2. Simulation Regions Summary for Winter

Region Name Winter

Reserve Margin

Modeled (%)

Peak Load (MW)

Available Transfer Capability into

Southern Company

Systems(MW)

CBM into Southern Company Systems

(MW)

TVA xxx 30762 809 300Duke Energy Carolina xxx 21032 230 350

SCEG xxx 5851 169 0

Santee Cooper xxx 4743 416 50

FPL xxx 23293 134 100Duke Energy FL xxx 10122 123 50

JEA xxx 2782 44 100

Power South xx 2581 300 -

OPC xxx 5717 Unlimited -

MEAG xxx 2240 Unlimited -

TAL xxx 634 18 -

MISO xxx 25577 1688 100

The topology used for the simulations is in Figure I.3.

PUBLIC VERSION

7

Figure I.3. Simulation Topology

It should be noted that the entirety of the MISO interconnection was not modeled. Rather, only those

entities directly interconnected to Southern (Entergy and Cooperative Energy) were modeled. These

entities were, however, jointly dispatched as a single entity to reflect operation within the MISO

footprint.

Sales and purchase transactions are simulated between regions when the market price in one region

is higher than an adjoining region and there is sufficient transfer capability. During extreme scenarios

when loads are high, and many units are in a forced outage state, prices can rise substantially higher

than the cost of a CT.

PUBLIC VERSION

8

Scarcity pricing is the price markets experience when they are short on available capacity and is driven

by several complex factors. While the scarcity pricing assumptions used in the Reserve Margin Study

have been calibrated to historical scarcity market prices, those relationships may not always hold.

During scarcity situations, the System will be subject to the market and, because of the importance of

service reliability, is expected to make purchases even at prices well above xxxxxxxxxxx if they are

reliably available.

A scarcity pricing curve, developed in conjunction with external consultant “ASTRAPE”, used eight

years (2010-2017) of historical market purchases to estimate the market purchase cost in scarcity

scenarios and is shown in Figure I.4 below. Scarcity prices could rise as high as xxxxxxxxxxx if a

region experiences a system emergency and shedding firm load is imminent. Scarcity prices are

incremental (in addition to) generation costs.

Figure I.4. Scarcity Pricing Curve

REDACTED

PUBLIC VERSION

9

During emergency conditions, the System procures as much energy from the marketplace as possible

and utilizes other peaking resources such as interruptible customers, voltage control, and emergency

hydro. If the System is still short the necessary capacity to meet load plus operating reserves, CBM is

utilized to obtain any additional energy that may be available. The System has CBM reservations on

ties with TVA, Duke Energy Carolinas, Entergy, South Carolina Public Service Authority, Florida Power

and Light, Duke Energy Florida, and JEA totaling 1,150 MW. This CBM capability was modeled and

utilized as needed in the analysis.

Despite the load diversity associated with the regional modeling discussed above, the actual

availability of purchases from other entities is not always as available as the SERVM model might

indicate. Southern Company’s Fleet Operations and Trading (“FOT”) organization has advised that

under extremely high summer load conditions, the availability of purchases in the marketplace is

unlikely to exceed xxxxxxxxx. Likewise, under extremely high winter load conditions, the availability of

purchases in the marketplace is unlikely to exceed xxxxxxxx. These limitations exist for two reasons.

First, during such extreme conditions, other market participants may also be experiencing conditions

that approach the limits of their own system. Therefore, even though the model may show some

available diversity between the regions, those entities may be unwilling to sell that capacity due to the

risks and uncertainty on their own systems. Second, during such extreme conditions, there is often a

high likelihood of transmission curtailments and so some capacity that may be available may not be

deliverable to the system – even if there is transmission interface capability available. These limitations

cannot be precisely modeled within SERVM, but a combination of both limits on sales price and hurdle

rates between regions has been implemented as a means of addressing these issues.

Merchant capacity has been present in the southeastern United States for over 15 years, but the

sporadic nature of its availability requires planners to be conservative in assumptions about its

presence in the future. Merchant capacity may be purchased by other load serving entities in the

region, may not have firm transmission, or may not have firm fuel supply. For these reasons, merchant

capacity was assumed to be unavailable in the base case simulations.

Load Forecast Uncertainty

In addition to variation from normal weather, there remains uncertainty in the peak load projections

when looking several years into the future. If load grows more quickly than expected, the reserve

PUBLIC VERSION

10

margin may not be sufficient unless that growth potential was properly considered in the reserve

margin assumptions. Unexpected strength or weakness in the economy is a primary source of this

load forecast error (“LFE”). An unforeseen change in electricity utilization and technology (e.g. heat

pumps, electric transportation, and energy efficiency) can also be a source of LFE.

The LFE assumptions used in the 2018 Reserve Margin Study were updated in the fall of 2017. Load

forecast uncertainty xxxxxxxxx into the future was estimated using xxxxxxxx of historical data. The

System has based its load forecast error assumptions on the xxxxxxxxxxxxxxxxxxxxxxxxxx forecast

growth of the economy and the assumption that there xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx

xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx. For the period xxxxxxxxxxxxx, the forecasts of xxxxxxxxx

xxxxxx for xxxxxxxxxx into the future were compared with actual xxxxxxxxxxxxx to determine 21

economic forecast errors. The economic forecast errors were multiplied by xxxx to determine 21 load

forecast errors ranging from a maximum under-forecast error of xxxxxx to a maximum over-forecast

error of xxxxxx. Each of the 21 LFEs has a xxxxx (xxxx) chance of occurring. By combining and

averaging similar LFEs, the 21 LFE points were converted to six LFE points as shown in the following

table. For example, points 2 (LFE = xxxxx), 3 (LFE = xxxxx), and 4 (LFE = xxxxx) were combined and

averaged to yield xxxxx, and the combined probabilities were summed to achieve a combined

probability of xxxxxxxxxxxxxxxxxxxxxxxxx). This was done to minimize the total number of runtime

simulations that would be required while still considering an accurate distribution of LFE possibilities.

Table I.3. Load Forecast Error

21 LFEs 6 LFEs

LFE Probability LFE Probability

x xxxxx xxxxx xxxxx xxxxx

x xxxxx xxxxx

xxxxx xxxxx x xxxxx xxxxx

x xxxxx xxxxx

x xxxxx xxxxx

xxxxx xxxxx

x xxxxx xxxxx

x xxxxx xxxxx

X xxxxx xxxxx

X xxxxx xxxxx

Xx xxxxx xxxxx

Xx xxxxx xxxxx

Xx xxxxx xxxxx Xxxxx xxxxx

PUBLIC VERSION

11

Xx xxxxx xxxxx

Xx xxxxx xxxxx

Xx xxxxx xxxxx

Xx xxxxx xxxxx

Xx xxxxx xxxxx

Xxxxx xxxxx Xx xxxxx xxxxx

Xx xxxxx xxxxx

Xx xxxxx xxxxx xxxxx xxxxx

xx xxxxx xxxxx

Using this distribution, the minimum and maximum LFE values used in this study are xxxxxx and

xxxxxx of the expected value, respectively.

Generating Unit Capacity Ratings

Unit ratings are traditionally established for both the summer and winter seasons. Summer ratings are

generally established to correspond to output under 95ºF ambient temperatures. Table I.4 below

shows the summer ratings associated with the nuclear, coal, and gas steam resources on the System.

Only resources for which Alabama Power has ownership or contractual rights are specifically named.

Other System resources are designated “SOCO Resource” in Table I.4.

Table I.4. Nuclear, Coal, and Gas Steam Unit Ratings

Unit Name Unit

CategoryPeak Rating@95F

(MW) BARRY_4 Coal 362

BARRY_5 Coal 738.5

FARLEY_1 Nuclear 874

FARLEY_2 Nuclear 877

GASTON_5 Coal 832

GORGAS_10 Coal 718.7

MILLER_1 Coal 656.24




SOCO RESOURCE Coal 700

PUBLIC VERSION

12




SOCO RESOURCE Nuclear 438.88


SOCO RESOURCE Coal 72.24












SOCO RESOURCE Nuclear 79




SOCO RESOURCE Nuclear 103









SOCO RESOURCE Gas 350.5

SOCO RESOURCE Gas 348.5

Winter ratings for nuclear and steam units are generally unchanged from the summer ratings. Ratings

for CT and CC resources, however, can vary significantly depending upon the ambient temperature.

PUBLIC VERSION

13

Official winter ratings for CT and CC resources are established to correspond to output at 40ºF ambient

temperatures. Those ratings are shown in Table I.5 and Table I.6 below.

Table I.5. System CT Ratings

SYSTEM CT RATINGS

Unit Name Peak

Rating@95F (MW)

Peak Rating@40F

(MW) AMEA_SYLAC_1 47.5 54.6

AMEA_SYLAC_2 47.5 54.6

Calhoun_CT_1 158 181.7




GASTON_A 16 18.4

GREEN_CT_10 85 97.8

GREEN_CT_2 84 96.6

GREEN_CT_3 82 94.3

GREEN_CT_4 81 93.2

GREEN_CT_5 82 94.3

GREEN_CT_6 81 93.2

GREEN_CT_7 80 92

GREEN_CT_8 83 95.5

GREEN_CT_9 82 94.3

SOCO RESOURCE 149 171.4



SOCO RESOURCE 75.2 86.5








PUBLIC VERSION

14






























SOCO RESOURCE 80 92

SOCO RESOURCE 80 92

SOCO RESOURCE 180 207





PUBLIC VERSION

15


SOCO RESOURCE 74.8 86




SOCO RESOURCE 40 46





























SOCO RESOURCE 33 38


PUBLIC VERSION

16






Table I.6. System CC Ratings

SYSTEM CC RATINGS

Unit Name Peak

Rating@95F (MW)

Peak Rating@40F (MW)

BARRY_6 550 616

BARRY_7 557.1 624





















PUBLIC VERSION

17

Nevertheless, SERVM has features that can utilize the ambient temperature curves so that the actual

output at the simulated system temperature can be modeled. Figure I.5 below shows the ambient

temperature curves (on a per unit output basis) that were modeled within SERVM.10

Figure I.5. Ambient Temperature Output Curves

Generating Unit Outage Rates

Generating units typically operate for a period, fail, are repaired, and then operate again. For example,

a unit may run from 500 to 1,500 hours before it fails, take from 3 to 500 hours to repair, then run again

for 500 to 1,500 hours.

Forced outage and maintenance outage data for the 2018 Reserve Margin Study consist of a series

of observations of historical outage events from 2006-2016. This data is assembled into time-to-fail

(“TTF”) and time-to-repair (“TTR”) distributions.

10 One or two CCs have unique designs resulting in their own, unique ambient temperature output curve. Those curves are not shown on the chart.

REDACTED

PUBLIC VERSION

18

Typical data for a unit might have up to five dozen entries in the TTF input data record, ranging from

just a few hours to as many as 12,000 hours. Likewise, the typical data will contain a corresponding

amount of entries in the TTR distribution, ranging from one to 2,500 hours. As the model processes

chronologically, it will randomly choose a TTF duration from the first data record and then randomly

choose a TTR duration. Individual unit operation, therefore, is a direct reflection of what has happened

over approximately ten years. Since units are independent of each other, it is possible that many units

can be down at once. An example of this type of input data for a steam unit is shown in Table I.7.

Table I.7. Steam Unit Sample Time to Fail and Time to Repair Data

Unit Name Time-to-

Fail

(hours)

Time-to-

Repair

(hours)

Sample

Plant

2747 4

1839 5

6710 11

573 4

333 5

530 1

233 2

215 2

752 1

3710 6

1338 2

Most steam units have their own specific outage history. However, the outage history of similar units

has been combined to get a robust set of data from which to take random outage draws. Units with

similar history and units for which no outage history was available were modeled using a similar

reference unit.

Partial outages are modeled using the same rigorous approach that is used for full outages. A

distribution is built for TTF events, TTR events, and the percentage derate. During the simulation, full

outages and partial outages are tracked and randomly drawn.

PUBLIC VERSION

19

The availability data for the System’s “CC” units are modeled similarly to steam, with appropriate

outage and derate TTF and TTR data. Additionally, in real-time operations, the supplemental modes

(i.e., full pressure (“FP”) and power augmentation (“PA”) of a CC) are dispatched separately from the

base operating mode. The supplemental modes have a higher heat rate value and, therefore, tend to

be dispatched during the same demand periods as CTs.

CT unit availability is generally driven by start failures. Once a CT starts, it is rare that it fails during

run-time. Within SERVM, all CT availability data has been modeled as a startup probability with TTR

data based on real observations. CT data include startup probabilities ranging from 85% to 99%.

Repair data range from 8 to 93 entries in the TTR input data records with values ranging from less

than an hour to nearly 100 hours.

To further refine outage rates, SERVM allows these historical TTF and TTR values to be scaled in

aggregate to achieve an expected outage rate. The historical TTF and TTR values were thus scaled

to get outage rates expected for each unit class (see Table I.8 below).

As the model progresses chronologically, it randomly chooses a time to fail duration from the TTF data

record and then randomly chooses TTR duration (for CTs, the failure is determined by a probability

draw when the startup is initiated and then the TTR is chosen randomly). Individual unit operation,

therefore, is a direct reflection of what has happened over the selected sample years of data. The

resulting forced outage rates, ratios of failed hours to operating hours, or ratios of failed hours to total

hours are thus outputs of the model rather than inputs. Because forced outage rates are an output of

the model, there can be minor differences in the resulting EFOR from case to case, but with sufficient

outage draw iterations in the simulation, the resulting EFOR should converge to an expected value.

The table below shows the resulting EFOR from one of the simulated runs, excluding any impacts

from cold weather-related outages, which should be approximately the same in all cases.

Table I.8. Approximate EFOR by Unit Class

Unit Class EFOR

(%)

Nuclear 1.9

Coal 2.9

Gas Steam 2.2

PUBLIC VERSION

20

Combined Cycle 1.6

CTs 5.2

Total System 2.7

The SERVM simulation randomly selects failure events and operating events for each unit. For every

hour, certain units will be operating, and other units will be in a failure state. To ensure the model

predicts these events accurately, a comparison was made of the simulated outage probability to the

actual outage probability. This comparison, shown in Figure I.6, confirms that the modeled outage rate

is consistent with the historical outage rate and indicates that the impact of outage events is adequately

modeled.

Figure I.6. Unplanned Outage Probability

Incremental Cold Weather Outages

The discussion of outage data in the previous sections describes the “base” level of outage expected

across the year. However, history has demonstrated that under extremely cold conditions, outage

rates can increase as coal piles and pipes begin to freeze, as oil thickens to the point that it will not

flow sufficiently to operate a facility, or as instrumentation and controls or other plant equipment begin

to freeze. These situations do not materialize until weather conditions are extreme, and these extreme

REDACTED

PUBLIC VERSION

21

weather conditions are less common. When they occur, however, the outage impacts can be

significant and can increase in an exponential manner. Historically, these incremental outages have

materialized at system weighted temperatures roughly xxxx and below. However, efforts to minimize

these impacts have been made in recent years and implemented across the system. Based on these

efforts, it is expected that performance improvements will be such that these incremental outages will

not begin to materialize until approximately xxxx, as shown in Figure I.7 below. The figure shows (a)

a trend of historical unit outages under various cold weather conditions (see Appendix A for more

detailed explanation of this trend), (b) an incremental trend of these outages assuming a xx underlying

system “EFOR”, and (c) a trend representing the assumptions used in this study that includes expected

performance improvements.

Figure I.7. Cold Weather Outage Assumptions

Planned Outage Patterns

Planned outages occur most often in the shoulder months because the demand on the units to run

during the peak demand months does not allow for a lot of down time. Traditionally, planned

maintenance events are not scheduled during either the summer months (June-September) or

January and February unless it cannot otherwise be avoided or for oil units in noncompliance zones.

While maintenance schedules are generated annually for the upcoming 5 years, the Reserve Margin

REDACTED

PUBLIC VERSION

22

Study is looking more generically and therefore allows the model to schedule maintenance around

anticipated peak load periods. The model schedules these maintenance outages during low demand

periods in such a way that the maintenance outage rate achieves the desired rate for the year. In

general, this results in planned maintenance modeled relatively consistent with actual practice. Figure

I.8 below shows the likelihood that a resource will be assigned a planned outage in any given month.

Figure I.8. Planned Outage Probability by Month

Commitment and Operating Reserves

Resources are committed to match current operating practices. Each week during a simulation, the

loads for each hour of the week are examined and the optimum dispatch is set to meet the system

peak load while maintaining the required operating reserves for every hour. The optimum dispatch

takes into consideration which units are available, the minimum uptimes and downtimes for each unit,

the startup costs and times for each unit, and the necessary required operating reserves. Operating

reserves are required by the Southern Balancing Authority, which is the entity responsible for

balancing load and generation in the region, to meet North American Electric Reliability Corporation

PUBLIC VERSION

23

(“NERC”) Reliability Standards. The Southern Balancing Authority provides guidance regarding the

amount of operating reserves that should be modeled based on their operational requirements. That

guidance included a total operating reserve requirement of xxxxxxxxx, broken down according to the

following components:

Regulating Reserves: xxxxxxxxxxxx of nominal solar capacity or xxxxxx

Contingency Reserve-Spinning: XXXXXX

Contingency Reserve-Supplemental (or Non-Spinning): xxxxx

In addition, the Southern Balancing Authority’s guidance established a firm load curtailment threshold

of xxxxxxx of total operating reserves, meaning that firm load should be curtailed to maintain a

minimum total operating reserve requirement of xxxxxxx. However, SERVM cannot model a fixed MW

operating reserve value for the purposes of firm load curtailment. Rather, SERVM can be configured

to curtail firm load to maintain Regulating Reserves plus Contingency Reserve-Spinning. Therefore,

only 496MW of Contingency Reserve-Spinning was modeled so that the sum of Regulating Reserve

and Contingency Reserve-Spinning did not exceed xxxxxxxxxx. The remaining xxxxxx of the xxxxxx

of operating reserves was modeled as Contingency Reserve-Supplemental, such that the final

modeled operating reserves were as follows:

Regulating Reserves: xxxxxx

Contingency Reserve-Spinning: xxxxxx

Contingency Reserve-Supplemental (or Non-Spinning): xxxxxx.

Dispatch Order

Generation resources are generally dispatched economically based upon dispatch prices. The

exceptions include energy-limited resources and non-dispatchable resources. Energy-limited

resources, such as hydro and pumped storage hydro, are typically scheduled based on availability of

water and expected system costs. Non-dispatchable resources, such as solar and wind vary with the

weather. Therefore, the dispatchable resources are typically optimized around the output of these

other non-dispatchable or pre-scheduled resources. Demand response resources either self-curtail

based upon price (e.g., Real Time Pricing programs) or are called whenever the system reaches

certain reliability conditions (such as a system alert). Figure I.9 below shows the dispatch stack order

PUBLIC VERSION

24

for the dispatchable resources modeled in the 2018 Reserve Margin Study. The chart excludes the

energy-limited, non-dispatchable, and demand response resources.

Figure I.9. System Dispatch Stack

Dispatchers’ Peak Load Estimate Error

The dispatchers’ peak load estimate error consists of three separate time periods, including day

ahead, four-hour ahead, and hour ahead. The amount of dispatcher’s peak load estimate error

modeled for each of these time periods was based on actual, historical forecast error data for the years

2012 through 2015. The table below shows the resulting mean and standard deviation that served as

the basis for the modeled dispatcher’s peak load estimate error.

Table I.9. Historical Dispatcher's Peak Load Forecast Error

Day Ahead

Mean

Day Ahead

Std Dev

4-Hour

Mean

4-Hour

Std Dev

Hour Ahead

Mean

Hour Ahead

Std Dev

January xxxx xxxx xxxx xxxx xxxx xxxx

February xxxx xxxx xxxx xxxx xxxx xxxx

March xxxx xxxx xxxx xxxx xxxx xxxx

REDACTED

PUBLIC VERSION

25

April xxxx xxxx xxxx xxxx xxxx xxxx

May xxxx xxxx xxxx xxxx xxxx xxxx

June xxxx xxxx xxxx xxxx xxxx xxxx

July xxxx xxxx xxxx xxxx xxxx xxxx

August xxxx xxxx xxxx xxxx xxxx xxxx

September xxxx xxxx xxxx xxxx xxxx xxxx

October xxxx xxxx xxxx xxxx xxxx xxxx

November xxxx xxxx xxxx xxxx xxxx xxxx

December xxxx xxxx xxxx xxxx xxxx xxxx

System-Owned Conventional Hydro Generation

System-owned hydro capacity of 2,400 MW (projected for the year 2025) was divided into two

components:

1) Scheduled Hydro

2) Emergency or “Unloaded” Hydro

This study includes 54 different hydro scenarios that are matched with the 54 weather scenarios. The

54 scenarios chosen are based on the past 54 years (1962-2015) of weather and hydro data. For each

of the scenarios, scheduled hydro capacity is modeled based on actual history.

The optimal dispatch of hydro resources is not solely an economic decision. Planners must consider

river flow requirements and impacts on other reservoirs in the same river system. During drought

conditions, it is rare that the full capacity of all hydro resources would be dispatched at the same time.

The total hydro capacity that is not used as part of the daily schedule would be available as emergency

hydro. Only in cases of extreme need is the emergency hydro capacity called upon to operate. Also,

the emergency hydro block is only available for a small number of events per year. To model this

within SERVM, the emergency hydro block is tied to a flex energy account to reflect the limited

availability of this emergency hydro energy. If the emergency hydro capacity is needed to meet load

during emergencies, the model will pull energy from this account. If the energy account becomes

depleted, the capacity will not be available during subsequent emergencies.

PUBLIC VERSION

26

Figure I.10 depicts the monthly energy produced by the two components of System-owned hydro

generation in a representative year, 1998. The figure illustrates the typical distribution of available

hydro energy across the months of the year.

Figure I.10. Hydro Energy Availability (1998 Example Data)

As with the weather data, the availability of hydro energy can vary year to year. Figure I.11 below

illustrates the total available scheduled hydro energies from the past 54 weather years (1962-2015).

REDACTED

PUBLIC VERSION

27

Figure I.11. Annual Scheduled Hydro Energies

SEPA Conventional Hydro

The Southeastern Power Administration (“SEPA”) conventional hydro is less flexible in its operation

than the System-owned hydro. The System has a contractual right to an allocation of the SEPA hydro

capacity. Within SERVM, SEPA conventional hydro is modeled as a standard hydro unit with minimum

daily dispatches. As currently modeled, the System is entitled to 477 MW taken over four hours per

weekday, with a minimum daily schedule of 637.8 MWh and a maximum monthly energy allocation of

14.162 GWh.

PUBLIC VERSION

28

Pumped Storage Hydro

Pumped storage hydro is a resource that is designed to pump water to an elevated reservoir using

energy at off-peak periods when prices are low, and to generate electricity by releasing that water at

times when prices are high. The dispatch of pumped storage is not simply a reliability decision,

although the reservoir should always be kept at a level where energy will be available for emergency

conditions. The System has a total of 540 MW of pumped storage resources spread across two

different locations (Wallace Dam and Rocky Mountain Pumped Storage Facility). The Rocky Mountain

Pumped Storage Facility is co-owned with Oglethorpe Power Corporation (“OPC”).

Demand Response Resources

Approximately xxxxxxxxx of DRR capacity (contract value) is included in the analysis for the summer,

and approximately xxxxxxxx are included for the winter. These DRR include such programs as

Interruptible Service (“IS”), Real-Time Pricing (“RTP”), Direct Load Control (“DLC”), Conservation

Voltage Reduction (“CVR”), and Stand-by Generation (“SBG”). The model reflects both the seasonal

availability as well as the contract constraints (e.g., hours per year, days per week, and hours per day)

for these energy-limited resources, so there is no need to adjust the contracts in the model by

multiplying by Incremental Capacity Equivalent (“ICE”) factors. In general, ICE factors represent the

worth of load management resources, such as an interruptible service contract, relative to the value

of incremental generating capacity that can be added to the system.

These resources occupy specific positions in the dispatch order as established by an assumed

dispatch price. The position in dispatch affects their ability to reduce EUE and alters the frequency

with which they are called. Some of these resources, such as RTP, are called based on economics

and have an assumed dispatch price associated with them that is consistent with the expectation of

the market prices that would result in self-curtailment by the customer. Others are called only to avoid

EUE, and their assumed dispatch price is used mainly to establish the priority in which these programs

are called. That priority is established based on how operations would anticipate them to be called in

a generation shortfall event and would result in CVR being called first, followed by DLC, then IS, and

finally SBG. Within the IS category, the programs are split into three blocks so that not all contracts

are called simultaneously.

PUBLIC VERSION

29

Renewable Resources

NOTE: Except as otherwise stated, the Southern Companies maintain the right to use the

electricity and all environmental attributes associated with all renewable projects discussed in

this report for the benefit of its customers. This includes the right to use the electricity and the

environmental attributes for the service of customers, as well as the right to sell environmental

attributes, separately or bundled with electricity, to third parties.

The amount of renewable resources modeled for the System includes

Biomass: 248 MW

Landfill Gas: 43 MW

Solar: 3,144 MW, and

Wind: 588 MW.11

Biomass and landfill gas resources were modeled like other resources with a fixed output level based

on their nominal capacity. However, the output of wind and solar resources are dependent upon

weather conditions and location. Except for a few of the wind resources on the System that have been

contracted based on a fixed hour-by-hour schedule, the output of the wind and solar resources varies

moment-by-moment, hour-by-hour, and year-by-year. These wind and solar resources have been

modeled with 8,760-hour profiles that are consistent with each of the 54 weather years as well as

consistent with their location. Because the profiles included in the model for these resources reflect

the hour-over-hour and year-over-year variances in output, there is no need to adjust the resources

by multiplying by ICE factors.

Natural Gas Availability

Natural Gas operates in accordance to the Gas Day (i.e., 9AM-9AM), whereas electricity operates

according to the Electric Day (i.e., Midnight to Midnight). Firm gas transportation is procured for the

fleet’s gas-fired units, but 24-hour Gas Day coverage is not procured for every plant. The amounts to

be procured are generally driven by the System’s Fuel Policy. Although case-specific situations may

11 Wind capacity listed includes certain fixed delivery wind energy contracts. The total wind capacity shown includes the amounts delivered from these contracts coincident with the System peak.

PUBLIC VERSION

30

allow for deviations from the Fuel Policy, for purposes of the 2018 Reserve Margin Study, all facilities

under control of the Operating Companies were modeled in compliance with the Fuel Policy unless

they had no contractual rights to dictate the amount of gas transportation to be purchased for the

facility.

SERVM models both firm and non-firm gas transportation and its associated availability. During

periods of high demand for natural gas, the System is limited to firm transportation contracts since

interruptible transportation is not available. This constraint has been incorporated into the modeling

process. The model begins phasing out interruptible transportation (i.e., it starts becoming unavailable)

when the daily minimum system weighted temperature falls below xxxx or when the daily maximum

system weighted temperatures rises above xxxx. When the daily minimum temperature falls below

xxxx or the daily maximum temperature rises above xxxx, no interruptible transportation is available

for that Gas Day. Figure I.12 below illustrates the availability of interruptible transportation as modeled

within SERVM.

Figure I.12. Interruptible Gas Transportation Availability Model

REDACTED

PUBLIC VERSION

31

Oil Availability

For dual-fuel (gas/oil) and oil-fired units, oil availability is dependent upon onsite storage. Storage

capacity is limited, so when gas is not available, onsite oil supply will deplete quickly. This may limit a

unit’s availability if refilling efforts cannot keep up with usage.

Capacity Cost

For the type of analysis performed in this study where the objective is to balance the cost of the

incremental capacity with the reliability benefits achieved by that capacity addition, it is necessary that

the capacity considered represents a true reliability addition, not an addition for both reliability and

energy economics. As such, simple-cycle CT technologies are the appropriate resources to be utilized

for the evaluation. Therefore, the cost associated with advancing a CT one year is the cost of capacity

used in the analysis. This cost is also known as the “economic carrying cost” or one-year deferral cost

associated with that resource. Since both summer and winter evaluations were performed in the 2018

Reserve Margin Study, economic carrying costs based on both summer and winter performance

characteristics were needed. The CT cost model is a green-field site of four dual-fueled units each

with a 95°F ambient temperature summer rating of xxx MW and a 40°F ambient temperature winter

rating of xxx MW, resulting in a summer performance economic carrying cost in 2025 dollars of

xxxxxxxxxxxxxxx and a winter performance economic carrying cost in 2025 dollars of xxxxxxxxxxxxx.

Cost of Expected Unserved Energy

To estimate the cost of EUE, Freeman, Sullivan & Company conducted an outage cost survey of

Georgia Power Company and Mississippi Power Company customers in 2011.12 This survey was

conducted among the following four customer classes:

Residential;

Commercial (below 1 MW average demand);

Industrial (below 1 MW average demand); and

Large business (commercial and industrial customers above 1 MW average demand).

12 While the survey only included customers from two Operating Companies, the results are considered appropriate for all Operating Companies, and so the cost of the survey was shared by all Operating Companies.

PUBLIC VERSION

32

The cost of EUE (in 2012$) for these four customer classes is shown in Table I.10 for both the summer

and winter periods. The cost of EUE was then adjusted by the customer weighting factor representing

recent relative weighting of customers in that class. The results of that weighting are also shown.

Table I.10. EUE Cost

EUE COST IN 2012 $

Outage Scenario Residential ($/kWh)

Commercial ($/kWh)

Industrial ($/kWh)

Large Business ($/kWh)

Weighted Average ($/kWh)

Weighting Factor (%) xxxxxx xxxxxx xxxxxx xxxxxx

1 hour, no warning, summer

xxxxx xxxxxx

xxxxxx xxxxxx xxxxxx

Contribution to Weighted Average

xxxxx xxxxxx xxxxx xxxxx

1 hour, no warning, winter

xxxxx xxxxxx xxxxxx xxxxxx xxxxxx

Contribution to Weighted Average

xxxxx xxxxxx xxxxx xxxxx

These estimated weighted costs of EUE were then escalated to 2025 dollars for use in the 2018

Reserve Margin Study. The result was a Value of Loss Load (“VOLL”) of xxxxxxxxxxx for summer and

xxxxxxxxx for winter.

PUBLIC VERSION

33

II. SIMULATION PROCEDURE

A. Case Specification

The simulations performed for the 2018 Reserve Margin Study were designed to estimate System

generation reliability across a wide range of weather conditions, LFEs, and reserve margins. Eleven

discrete reserve margin levels were simulated to calculate the expected costs over a broad range of

scenarios. Load shapes corresponding to the 108 weather datasets (54 weather years, each with

Tuesday and Saturday start days), were run in combination with varying LFEs. Weather years were

paired such that loads, hydro scenarios and renewable profiles were consistent. The simulation

variables were as depicted in Table II.1.

Table II.1. SERVM Case Variables

Weather and Hydro Years Summer/Winter

Reserve Margins LFEs

1962-2015 10%/17.0% xxxxx

11%/18.2% xxxxx

12%/19.5% xxxxx

13%/20.7% xxxxx

14%/21.9% xxxxx

15%/23.1% xxxxx

16%/24.4%

17%/25.6%

18%/26.8%

19%/28.0%

20%/29.3%

The winter reserve margins are the equivalent of their summer counterparts. Thus, the winter reserve

margins are not listed in whole percentage point increments.

Positive LFE represents an over forecasted load, meaning actual load was less than forecasted load.

Without accounting for load forecast uncertainty, the total number of combinations for the analysis

would be 54 × 2 × 11, or 1,188 cases. Considering the six load forecast points yields 7,128 cases

(54 × 2 × 11 × 6 cases). Each of these cases were then evaluated 100 different times, each with a

different set of random forced outage draws on the generating resources, yielding 712,800 production

cost simulations (54 x 2 x 11 x 6 x 100 cases). Estimating EUE for each of the 712,800 simulations

provides sufficient data for regression analysis of other combinations not specifically simulated. This

PUBLIC VERSION

34

set of simulations was performed for both the traditional analysis as well as the winter focus analysis

and the summer focus analysis.

B. Probabilities of Occurrence for Input Variables

As discussed in the previous sections, the chronological variable inputs into the model are used to

represent appropriate ranges of data. For example, the weather years selected to exemplify load

variations due to temperature changes represent 54 years of historical data. This is also true for the

hydro patterns and solar profiles developed. Each, however were modeled twice – once with a

Saturday start and once with a Tuesday start – resulting in 108 different weather/hydro datasets. The

implementation of load forecast uncertainty into the evaluation is representative of the potential

(supported by historical information) LFEs when considering the future. Each of the six forecast errors

has its own probability of occurrence that is related to the probability of error in forecasted economic

indicators. For each reserve margin studied, the combined set of input variables results in 648

individual cases having their own designated probability of occurrence to be used in the probabilistic

evaluation. Table II.2 depicts the probabilities assigned to each of these variables and the resulting

probability for each case. This total case probability is determined by combining the probabilities of

the determinant variables. The weather years and start days all have equal probability of occurrence.

Table II.2. Simulation Case Probability

LFE LFE

Probability Weather/Hydro

Probability Start Days Probability

Total Case Probability

xxxxx 0.0952 0.018519 0.5 0.000882

xxxxx 0.1429 0.018519 0.5 0.001323

xxxxx 0.2381 0.018519 0.5 0.002205

xxxxx 0.3333 0.018519 0.5 0.003086

xxxxx 0.1429 0.018519 0.5 0.001323

xxxxx 0.0476 0.018519 0.5 0.000441

C. Reliability Model Simulations

SERVM incorporates Monte Carlo techniques to conduct generation reliability simulations. Monte

Carlo analysis uses a random number generator to determine generating unit availability for the

System. For each iteration, the model simulations will randomly select the state of a generating unit

as fully operational, partially failed, or completely failed and determine if the system experiences loss

of load and associated EUE.

PUBLIC VERSION

35

For each of the 648 cases, each hour of the year was modeled with 100 draws from the distribution of

generating unit outage and duration data to determine if there exists a deficiency of generating

capacity to meet load demand. The 100 iterations were averaged together to establish a case-specific

result. A deficiency of generating capacity in any hour is recorded as a loss of load hour. The

magnitude of the outage during that hour is measured by EUE. The EUE is then aggregated by month

and multiplied by the respective value of lost load for that month to determine the EUE cost. The

monthly EUE costs are then summed together for the year to determine EUE cost for that case. The

case EUE cost is then multiplied by the probability of occurrence for that case and the results for all

cases are summed to determine the expected value of EUE cost for that reserve margin simulation.

This process is repeated to determine the expected value of generation costs, import costs,

emergency purchase (or sales) costs, the cost of non-firm outages (i.e., demand response costs), and

costs associated with non-spinning reserve shortfalls.

For each reserve margin simulation, the expected value of generation costs and import costs are then

summed together to establish “Production Cost”. Likewise, the expected value of emergency

purchases (or sales), demand response costs, costs associated with non-spinning reserve shortfalls,

and EUE costs are summed together to establish “Reliability Cost.” Figure II.1 shows the formula

used for calculating EUE. Other components are calculated similarly.

�� = �(�� ∗ ��

�

��

)

where

� = �� ,

� = ��

Figure II.1 Variable Calculation Formula

Table II.3 thru Table II.6 provide an example of implementing the formula for a sample data set

containing the 10 worst Reliability Cost cases. Table II.3 shows the Reliability Cost components with

their per unit weighted costs. Table II.4 shows the probability weighting of the Total Reliability Cost.

For illustrative purposes, all calculations are for a 17% summer reserve margin simulation.

PUBLIC VERSION

36

Table II.3. Sample Calculation Top 10 Worst Reliability Costs at 17% Summer Reserves

Table II.4. Worst Reliability Costs Weighted Probability

Data

Set

Probability Emergency

Purchases

($M)

EUE ($M) Demand

Response

Calls ($M)

Loss of

Non-Spin

($M)

Total

Reliability

Cost ($M)

Weighted

Reliability

Cost ($M)

1 xxxxxxx xxxx xxxx xxxx xxxx xxxx xxxx





Data

Set

Emergency

Purchases

(MWh)

Emergency

Purchases

Cost

($/MWH)

EUE

(MWh)

EUE Cost

($/MWH)

Demand

Response

Calls (MWh)

Weighted

DR Cost

($/MWH)

Loss of

Non-

Spin

Reserve

(MWh)

Loss of

Non-

Spin

Cost

($/MWH)

1 xxxx xxxx xxxx xxxx xxxx xxxx xxxx xxxx










PUBLIC VERSION

37






A similar calculation is performed for the components of Production Cost as demonstrated in Table

II.5 and Table II.6 for the same 10 cases shown above.

Table II.5. Production Cost Components for Sample Data Set

Data

Set

Generation

Costs

($M)

Purchases

(MWh)

Purchase

Cost

($/MWH)

1 xxxxxxx xxxxxxx xxxxx










Table II.6. Production Cost Weighted Probability

Data Set Probability Generation

Costs ($M)

Purchase

Cost

($M)

Total

Production

Cost ($M)

Weighted Total

Production Cost

($M)

1 xxxxxxxx xxxxxxxx xxxxxx xxxxxxxx xxxxx




PUBLIC VERSION

38







By applying regression analysis to the expected values of Production Cost and Reliability Cost, a curve

summarizing the Production Cost, Reliability Cost, and Incremental Capacity Cost as a function of

reserve margin was developed. These results are discussed in detail in the next section.

PUBLIC VERSION

39

III. BASE CASE RESULTS

A. Traditional Study Results

In theory, the economic optimum reserve margin, or the EORM, should be the reserve margin that

results in the minimum total system costs. The three components of total system costs (Production

Cost, Reliability Cost, and Incremental Capacity Cost) that vary across reserve margin levels were

added together to create an aggregate total system cost curve (the “U-Curve”). The minimum point on

the resultant U-Curve, which is at 15.25%, represents the EORM. This graph is presented below.

Figure III.1. Traditional EORM U-Curve

REDACTED

PUBLIC VERSION

40

B. Winter-Focused Reserve Margin Results

The 2015 Reserve Margin Study identified several drivers associated with issues during extreme cold

weather. Those drivers included:

a. the narrowing of summer and winter weather-normal peak loads,

b. the distribution of peak loads relative to the norm,

c. cold-weather-related unit outages,

d. the penetration of solar resources, and

e. increased reliance on natural gas.

In addition to these same drivers, the 2018 Reserve Margin Study identified an additional constraint –

the availability of market purchases (see Assumptions section of this report). Because all these drivers

will impact winter reliability, it has been determined that even though the System remains a summer

peaking utility for the time being, the System’s primary reliability risk is in the winter, resulting in the

need for a Winter TRM. Appendix A addresses this need for a Winter TRM more thoroughly, but as

an example of this need, Figure III.2 below shows seasonal EUE by reserve margin. As indicated by

the chart, at low reserve margins, summer and winter have relatively equal expectations of EUE – with

summer being higher at very low reserve margins. However, as reserve margins increase, the

expectation of EUE in the summer reduces drastically. Similarly, the expectation of EUE in the winter

falls as reserve margin increases, but not as drastically and even at 20% reserve margin, there is still

a significant expectation of potential loss of load.

PUBLIC VERSION

41

Figure III.2. Seasonal EUE by Reserve Margin

To address this winter reliability risk, a Winter TRM is necessary. Therefore, a separate analysis was

performed where the focus of the study was on a winter reserve margin. Traditionally, the reserve

margin is stated in summer terms – that is, stated in terms of summer peak loads and summer resource

ratings. For example, the reserve margins in Figure III.2 above are all stated in summer terms. The

traditional analysis is performed by developing the 108 historical weather load shapes in such a way

as to ensure the average summer peak load from all 108 load shapes equals the summer peak

demand forecast for the study year. To perform the winter focused reserve margin analysis, the 108

load shapes were adjusted such that the average of the winter peak loads equaled the winter peak

demand forecast. The results of the study were then stated in winter reserve margin terms rather than

summer reserve margin terms (i.e., stated in terms of winter peak loads and winter resource ratings).

The minimum point on the resulting U-Curve was established as 22.5% as shown in the graph below.

REDACTED

PUBLIC VERSION

42

Figure III.3. Winter EORM U-Curve

It is important to recognize that while the EORM from the winter U-Curve occurs at a reserve margin

that appears to be significantly higher than the EORM from the traditional, summer-oriented U-Curve,

the EORM from the two cases represent similar levels of reliability and cost for the same underlying

system. Each study contains a full year of hourly production cost simulations which inherently reflect

8,760 reserve margin levels. Therefore, the difference in absolute value (22.5% versus 15.25%)

primarily a function of stated terms, with the summer EORM being stated in terms of summer capacity

ratings and the summer weather-normal peak load and the winter EORM being stated in terms of

winter capacity ratings and winter weather-normal peak load.

C. Summer-Focused Reserve Margin Results

Given that the System’s primary reliability risk is in the winter, it is possible to determine a summer-

focused reserve margin without consideration of some of the key winter drivers, specifically without

the incremental cold-weather generation outages or the natural gas fuel constraints. The idea behind

REDACTED

PUBLIC VERSION

43

this analysis is to determine the corresponding Summer TRM once the Winter TRM has been

established. The following graph shows that a summer-focused EORM without those key drivers would

be 14%.

Figure III.4. Summer EORM U-Curve (Without Key Winter Drivers)

D. Risk Analysis

The winter-focused combination of Production Cost, Reliability Cost, and Incremental Capacity Cost

results in a EORM of 22.5%. However, since Production Cost and Reliability Cost are highly

dependent on the selected scenario, consideration of only the EORM does not give a complete picture.

Figure III.5 illustrates the volatility in Production Cost and Reliability Cost exposure. In scenarios in

which load grows faster than expected, temperatures are higher than expected, or unit performance

is poorer than expected, the cost exposure can be much higher than the expected case.

REDACTED

PUBLIC VERSION

44

Figure III.5. Production and Reliability Cost Distributions for Winter Reserve Margins

Zooming in on the most extreme cases shown in Figure III.5 for each reserve margin further highlights

the risk in carrying low reserves. Figure III.6 shows the exposure for the top 10% of all cases as ranked

by Production Costs and EUE cost exposure. The most extreme case simulated at a 17% winter

reserve margin shows over xxxxxxxxxx per year in total exposure, while the most extreme case at a

26% reserve margin is approximately xxxxxxxxx.

REDACTED

PUBLIC VERSION

45

Figure III.6. Top 10% Distribution for Winter Reserve Margins

To more appropriately perform a comparison between highly volatile Production Costs and Reliability

Costs and fixed Incremental Capacity Cost, thus protecting against the potential for an extremely high

cost outcome, additional risk analyses should be performed. In the casualty insurance business,

customers have the option of paying an insurance premium to cover the impact of a catastrophic loss.

In this example, the annual insurance premium is higher than the cost of the loss times its probability.

Customers and regulators are comfortable with paying an amount greater than the average loss

because it makes the payments fixed. In the same way, utilities can procure capacity at fixed rates

slightly above the EORM to prevent the possibility of certain high cost outcomes. The approach taken

to evaluate the risk of these potential high cost outcomes and thus determine how much of an

“insurance premium” to pay is to use a risk metric called Value at Risk (“VaR”).

VaR is defined as the difference in cost at the expected value and the cost at some specified

confidence interval (e.g., the 85th percentile of risk). The VaR accounts for the customers’ exposure to

REDACTED

PUBLIC VERSION

46

higher costs above normal conditions. The VaR analysis looks at the incremental increase in expected

cost to move from one reserve margin to the next reserve margin and compares that with the

incremental decrease in VaR. So long as the incremental increase in expected cost is less than the

incremental decrease in VaR, the premium (i.e., the increased expected cost) is justifiable to protect

against the potential high cost outcomes. The point at which the incremental increase in cost equals

the incremental decrease in VaR represents the EORM at that confidence interval (as opposed to the

EORM at the weighted average).

The table below illustrates the VaR at the 80th (VaR80), 85th (VaR85), 90th (VaR90), and 95th (VaR95)

percentiles of confidence for a range of winter reserve margin targets.

Table III.1. Value at Risk

Reserve Margin Expected Cost

(M$) VaR80 (M$)

VaR85 (M$)

VaR90 (M$)

VaR95 (M$)

xxxxxx xxxxxx xxxxxx xxxxxx xxxxxx xxxxxx























PUBLIC VERSION

47







For the 80th percentile of risk (VaR80), the incremental increase in expected cost roughly equals the

incremental decrease in VaR80 when moving from 25.75% reserve margin to 26% reserve margin.

At this point, the incremental increase in cost is xxxxxxxxxxxxxxxxxxxxxxxxxxxxx; and the decrease

in VaR80, or decrease in customers’ exposure to higher cost outcomes, is xxxxxxxxxxxxxxxxxxx

xxxxxx. Moving from 26% to 26.25% results in an increase in expected costs xxxxxxxxxxxxxxxxxxxx

xxxxxxxxxxxxxxxxx that is greater than the decrease in VaR80 xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx.

Thus, 26% represents the EORM at the 80th percentile of risk. Compared to the expected case TRM

of 22.5%, a 26.0% reserve margin reduces the VaR80 exposure by xxxxxxxxxxx while only increasing

the expected case cost by xxxxxxxxxxx. Higher confidence intervals were also examined. At the 85th

percentile of risk, it would be justifiable to establish a reserve margin of 26.25%. At the 90th percentile

of risk, it would be justifiable to establish a reserve margin of 27.25%. Likewise, at the 95th percentile

of risk, it would be justifiable to establish a reserve margin of 28.5%. However, the increased expected

cost for these three confidence intervals are xxxxxxxxx, xxxxxxxx, and xxxxxxxxxxx, respectively.

While justifiable from a cost/risk reduction perspective, the absolute increase in expected cost

suggests use of the 80th or 85th confidence interval as there is a much bigger jump in expected costs

moving to the 90th confidence interval.

Another way to explain and understand the risk analysis used in this study is to realize that the VaR

analysis essentially establishes the EORM at the specified confidence interval. In other words, the

Operating Companies calculate the EORM at the expected value of cost. However, because of risk, it

would be justifiable to calculate the EORM at, for example, the 80th percentile of cost. This is precisely

what the Var80 analysis accomplishes – the economic balance between cost and risk. Figure III.7

below shows the total cost (Production Cost plus Reliability Cost plus Incremental Capacity Cost) at

the 80th confidence interval. The resulting “U-Curve” confirms that the EORM at the 80th confidence

interval is 26.0% - that is, 26.0% is the risk-adjusted EORM at the 80th confidence interval.

PUBLIC VERSION

48

Figure III.7 80% Confidence Interval U-Curve

E. Loss of Load Expectation

Some regions throughout the country utilize Loss of Load Expectation (LOLE) as their primary

resource adequacy reliability metric, while others either do not consider it or consider it as a secondary

metric to the EORM. LOLE is the probabilistic count of the number of days in the study year in which

the system experiences firm load shed of any duration. This metric does not measure the magnitude

of the event and is relatively sensitive to several input assumptions. The most common business

practice for those who use this metric is an LOLE value of 0.1 days per year, which is sometimes

referred to as a one day in ten years (1:10 LOLE) reliability criterion. An LOLE of 0.1 days per year

presumes there is a 10% probability of a loss of load due to generation shortfall in any one year or an

expectation that there would only be one loss of load event every 10 years.

Historically for the Southern Company System, this 1:10 LOLE threshold has occurred at reserve

margins below the EORM. Thus, the primary focus has historically been on the risk-adjusted EORM

REDACTED

PUBLIC VERSION

49

to establish the TRM. However, as the Company continues to incorporate new reliability risks in its

reliability modeling, more recent analyses have indicated that the LOLE for the System is much higher

than previously expected. Thus, the reserve margin necessary to maintain the 1:10 LOLE threshold is

also higher. Figure III.8 below illustrates how this metric looks for the System over the range of reserve

margins studied for the 2018 Reserve Margin Study as compared to the 2012 and 2015 reserve margin

studies. The reserve margins are shown in summer terms since neither the 2012 nor the 2015 studies

included a winter analysis.

Figure III.8. Loss of Load Expectation by Summer Reserve Margin

At its current approved Target Reserve Margin of 16.25% (which is equivalent to a 24.7% winter

reserve margin), the System has an LOLE of xxxxxxxxxxxx or an expectation of one event in xxx

xxxxx, which is below the 1:10 LOLE threshold. As indicated by the chart, to achieve a 1:10 LOLE

threshold would require a 17% Summer TRM. Figure III.8 was shown in summer terms as a

comparison to previous, traditional studies. However, since the increase in observed LOLE is

REDACTED

PUBLIC VERSION

50

associated with winter reliability issues, it is necessary to review these metrics as generated by the

winter focus study. Figure III.9 below shows the LOLE for the winter reserve margins evaluated.

Figure III.9 LOLE for Winter Reserve Margins

At the winter EORM of 22.5%, the LOLE is xxxxxxxxxxxxxxx or an expectation of one event every

xxxxxxxxx. To achieve a 1:10 LOLE threshold would require a winter reserve margin of 25.25%. In

both the traditional study and the winter focus study, the 1:10 LOLE threshold is above EORM but still

below the VaR85 reserve margin. At the VaR85 reserve margin of 26.25%, the LOLE expectation is

one event every xxxxxxxxxxx.

It would not be appropriate to establish a TRM that has an expected level of reliability that is lower

than common industry practice. For this reason, consideration of the 1:10 LOLE threshold as a

determinant in making a final TRM recommendation is necessary and appropriate.

REDACTED

PUBLIC VERSION

51

F. Total System Cost Components

The total system cost is the sum of three components:

1) The annual carrying cost of CTs added for reserve margin (Incremental Capacity Cost);

2) Reliability Costs; and

3) Production Cost.

Following is a discussion of each component.

1) Annual Carrying Costs of CTs

The incremental annual capacity carrying cost of the added capacity at any given reserve margin is

determined by multiplying the incremental CT kW capacity by its economic carrying cost. For the

traditional and summer focus studies, this cost was determined using summer performance values,

resulting in a carrying cost of xxxxxxxxxxxxxxx. To achieve an increase of one percent reserve

margin in the summer studies requires the addition of xxxxxxxxx or xxxxxxxxxxx in carrying cost.

For the winter focus study, the cost was determined using winter performance values, resulting in a

carrying cost of xxxxxxxxxxx. To achieve an increase of one percent reserve margin in the winter

focus study requires the addition of xxxxxxxx or xxxxxxxxxxx in carrying cost. As more CTs are

added to achieve a higher reserve margin, these carrying costs accumulate with the megawatts

added. This is represented in Figure III.10 (for the winter focus study), which shows a linear increase

in costs when graphed as a function of reserve margin.

PUBLIC VERSION

52

Figure III.10. Incremental Capacity Cost (Winter Focus)

2) Reliability Costs

Reliability Costs are the sum of the cost of EUE, the cost of any shortfalls in meeting required operating

reserves, the cost of emergency purchases (or sales), and cost of demand response calls. The cost

of EUE is determined by multiplying the amounts of EUE in MWh at each reserve level created in the

analysis by the assumed cost of EUE in $/MWh (with EUE in the winter being multiplied by the winter

cost of outage and EUE in all other months multiplied by the summer cost of outage). The cost of

meeting shortfalls in spinning and regulating reserves are included in the cost of EUE as the model

curtails load to maintain these requirements. The cost of meeting supplemental (i.e., non-spin) reserve

requirements is determined by the scarcity price at the time of the shortfall. The cost of demand

response calls is determined by the presumed dispatch price for each demand response program as

established by the Operating Companies. Figure III.11 illustrates Reliability Cost as a function of winter

reserve margin.

PUBLIC VERSION

53

Figure III.11. Reliability Cost

3) Production Cost

Production Costs include the variable operating costs of units plus the cost of any purchases with

neighboring regions less the cost of any sales with neighboring regions. Production costs at each

reserve margin level can be seen in Figure III.12.

PUBLIC VERSION

54

Figure III.12. Production Cost

As expected, Reliability Costs and Production Costs decrease as reserve margin increases.

Conversely, their costs increase as the reserve margin is reduced.

PUBLIC VERSION

55

IV. SENSITIVITY ANALYSES

The basis of the data for unit performance, weather, load forecast error, hydro availability, market

prices, and other inputs is from historical information. Other data such as market availability is based

on forecasted information. While the broad range of scenarios analyzed capture extreme events and

market prices, there remains risk that conditions could occur in the future that extend beyond the range

of what is contemplated in the base case model. Each of the following sensitivities were modeled to

examine their impact on both the EORM and the 1:10 LOLE threshold.

In addition to the sensitivities related to the uncertainties above, a sensitivity was modeled to determine

how the optimum reserve margin would change if the load forecast uncertainty was reduced to

determine a short-term reserve margin target.

A. Capacity Price

Capacity price has an inverse impact on the EORM. The EORM calculation assumes the addition of

a reliability resource (i.e., a CT) that has little or no energy value. This ensures a fair comparison of

capital cost against Production Cost and Reliability Cost. At lower capacity prices, it is economically

justifiable to have a higher TRM. Conversely, if capacity prices are higher, the EORM will be lower.

The capacity price used in the 2018 Reserve Margin Study represents the economic carrying cost of

a CT. The capacity price sensitivity examined a range of capacity costs from values as low as the

Budget 2018 Retail Capacity Price Forecast (“RCPF”) to values higher than the economic carrying

cost of a dual fuel CT. Figure IV.1 shows how capacity costs across these ranges affect the Winter

EORM. For example, at the 2025 RCPF of xxxxxxxxxx, the Winter EORM moved from 22.5% to more

than 29%. Capacity price does not impact the 1:10 LOLE threshold.

PUBLIC VERSION

56

Figure IV.1. EORM as a Function of Capacity Price

B. Minimal Cost of EUE

Two cost-of-EUE sensitives were evaluated. The first was a minimum value assuming only impacts

from residential class customers. This resulted in a cost of EUE of approximately xxxxxxxxxxx of

outage (in 2025$). The Winter EORM for this sensitivity moved from 22.5% to 20.5%. There was no

change in the 1:10 LOLE threshold.

C. Publicly Available Cost of EUE

The second cost of EUE sensitivity was one that was developed based on publicly available cost of

EUE data. Using the Interruption Cost Estimate Calculator, developed by Nexant and funded by

Lawrence Berkeley National Laboratory and the Department of Energy and is publicly available at

http://icecalculator.com, a cost of EUE for the System was estimated to be approximately

PUBLIC VERSION

http://icecalculator.com/

57

xxxxxxxxxxxxxxxxxxxxx. The Winter EORM for this sensitivity moved from 22.5% to 23.0%. There was

no change in the 1:10 LOLE threshold.

D. No Cold Weather Outage Improvements

As indicated in the Section I, Assumptions, the cold weather outage assumptions used in the 2018

Reserve Margin Study incorporated substantial unit performance improvements over historical actual

performance. This sensitivity assumes those performance improvements are not realized and the

future cold-weather outage performance is consistent with historical performance. The Winter EORM

for this sensitivity did not significantly change from the base case. However, the 1:10 LOLE threshold

moved from 25.25% to 25.75%.

E. Higher Scarcity Price Curve

For the 2018 Reserve Margin Study, the scarcity price curve was updated, resulting in significantly

lower scarcity price curves. Because the scarcity price curve is based on recent historical market

conditions, it is possible that the current assumptions for the scarcity price curve are biased low due

to the general high levels of current reserve margins throughout the neighboring regions. As the actual

reserve margins in the neighboring regions all decrease towards their respective target reserve

margins, it is anticipated that scarcity prices could return to levels seen previously. This sensitivity

assumes that the scarcity price curve would be more consistent with that used in prior reserve margin

studies (2012 and 2015). The Winter EORM for this sensitivity moved from 22.5% to 23.75%. The

1:10 LOLE threshold moved from 25.25% to 24.75%.

F. 50% Reduced Transmission

For this sensitivity, transmission capabilities with neighboring regions were reduced by 50%. This

resulted in an increase in the Winter EORM from 22.5% to 23%. It also resulted in an increase in the

1:10 LOLE threshold from 25.25% to 25.5%.

G. 50% Increased Transmission

For this sensitivity, transmission capabilities with neighboring regions were increased by 50%. The

results of the 50% increased transmission scenario showed no change in the Winter EORM. However,

the 1:10 LOLE threshold decreased from 25.25% to 25%.

PUBLIC VERSION

58

It should be noted that both the 50% Reduced Transmission sensitivity and 50% Increased

Transmission sensitivity only resulted in marginal changes in reliability (with little or no change in

economics). Together, this indicates that transmission interface capability with the interconnected

regions is adequate from a reliability standpoint.

H. 50% Higher Base EFOR

For this sensitivity, base level unit outages were increased by 50%. Incremental cold-weather outages

were not impacted by the sensitivity. The 50% higher unit outage scenario resulted in an increase in

the Winter EORM from 22.5% to 23.25%. Similarly, the 1:10 LOLE threshold increased from 25.25%

to 26.75%.

I. 50% Lower Base EFOR

For this sensitivity, base level unit outages were decreased by 50%. Incremental cold-weather outages

were not impacted by the sensitivity. The 50% lower unit outage scenario resulted in a reduction in the

Winter EORM from 22.5% to 21.55%. Similarly, the 1:10 LOLE threshold decreased from 25.25% to

23.75%.

Summary of Sensitivity Analyses

Figure IV.2 below shows a graphical representation of the results of all the sensitivity analyses (i.e.,

Sensitivities A through I). For Sensitivity A (capacity costs), two results are shown, representing

capacity prices associated with the Budget 2018 RCPF (A) and ½ of the economic carrying cost of a

CT (A’). The chart shows both Winter EORM and the 1:10 LOLE threshold. Together, they

demonstrate that the sensitivity analyses validate the base case results of the 2018 Reserve Margin

Study and indicate that its results are robust against those sensitivities.

PUBLIC VERSION

59

Figure IV.2. Summary of Winter Sensitivity Results

Short-Term Load Forecast Error

For this sensitivity, short-term load forecast errors were used. This sensitivity resulted in the Winter

EORM decreasing from 22.5% to 22.0%, reflecting a difference in long-term and short-term reserve

margins of 0.5%. The short-term load forecast errors used are in the following table.

PUBLIC VERSION

60

Table IV.1. Short-Term Load Forecast Error

SHORT-TERM LOAD FORECAST ERROR

LFE Probability

xxxxx 0.0833

xxxxx 0.1250

xxxxx 0.25

xxxxx 0.2917

xxxxx 0.1667

xxxxx 0.0833

PUBLIC VERSION

61

V. CONCLUSION

Winter reliability issues drive the 2018 Reserve Margin Study results. Therefore, a Winter TRM is

required to ensure the appropriate level of resource adequacy.13 However, it is necessary to establish

both a Winter TRM and a Summer TRM for several reasons. It is possible that capacity needs can be

driven by either season and should be considered when adding new capacity. In addition, there is the

potential that, over time, changes in rate structures, demand-side programs, and other initiatives could

alter the dynamics of the system such that the primary risk shifts between seasons. Therefore, it is

recommended, that a TRM be set for both seasons, with the Winter TRM established based on the

results of the winter focused study and the Summer TRM established based on the summer focused

study with 1:10 LOLE threshold considerations for both as discussed below.

Winter Target Reserve Margin

The 2018 Reserve Margin Study recommends a long-term Winter TRM of 26% based on the following:

1. The TRM should be greater than the 1:10 LOLE threshold of 25.25% to ensure an adequate

level of reliability on the System;

2. A reserve margin of 26% represents the risk-adjusted EORM at the 80th confidence interval

(the 80th percentile of risk – i.e., VaR80);

3. Compared to the 22.5% expected case EORM, a 26% risk-adjusted EORM reduces VaR at

the 80th confidence interval by xxxxxxxxxx while only increasing expected cost by xxxxxxxxxxx;

4. Compared to the 25.25% 1:10 LOLE threshold, a 26% risk-adjusted EORM reduces VaR at

the 80th confidence interval by xxxxxxxxxx while only increasing expected cost by xxxxxxxxxx;

and

5. A 26% Winter TRM is consistent with results from the 2015 Reserve Margin Study,14

confirming the results of that study.

13 See Appendix A for further justification of the need for a Winter TRM.

14 In the 2015 Reserve Margin Study, “An Economic Study of the System Planning Reserve Margin for the Southern Company System” (January 2016), the winter equivalent of the approved 16.25% TRM would have been 26%.

PUBLIC VERSION

62

Summer Target Reserve Margin

The Summer EORM from the summer focus study is 14.0%, with the VaR85 reserve margin being

18%. However, the Summer TRM cannot be determined without consideration of the Winter TRM. If

the System is meeting its 26% Winter TRM requirement with resources that provide year-round

capacity, the summer reserve margin will generally be at or above 17.3%. This means that the Winter

TRM is driving the System reliability, even though the next capacity need for one or more of the

Operating Companies may still be in the summer. However, in the event seasonal resources (such as

winter-only resources) are made available, it may be possible to lower the Summer TRM below 17.3%

- so long as the combined annual reliability remains above the 1:10 LOLE threshold. The following

graph demonstrates the minimum acceptable Summer TRM as a function of Winter TRM. For a Winter

TRM of 26%, the minimum acceptable Summer TRM is xxxxxxxxxxxxxxxxx

xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx.

Figure V.1. Minimum Acceptable Summer Target Reserve Margins

REDACTED

PUBLIC VERSION

63

The recommendation, therefore, is to establish a Winter TRM of 26%, while maintaining the currently

approved 16.25% as the Summer TRM. This recommendation would apply for studies looking out four

or more years. For studies looking inside a three-year window, the recommended Winter and Summer

TRM are 25.5% and 15.75% respectively, reflecting a 0.5% reduction from the long-term TRM resulting

from the difference between the long-term forecast error and the short-term forecast error.

These recommendations are designed to provide guidance for resource planning decisions but should

not be considered absolute requirements. The large size of capacity additions, the availability and

price of market capacity (as indicated by the Capacity Cost sensitivity), or economic changes may

justify decisions that result in reserve margins above these targets.

Components of the Target Reserve Margin

Figure V.2 shows the contribution of each of the components of uncertainty (weather, market risk, unit

performance, load forecast error, and fuel supply) toward the overall required Winter TRM of 26%.

Figure V.2. Economic Components of Winter TRM

PUBLIC VERSION

64

Likewise, Figure V.3 shows how each of the components contribute to the minimum Summer TRM of

16.25%.

Figure V.3. Economic Components of Summer TRM

The 26% Winter Target Reserve Margin recommended for the System reflects the results of the

economic study and a variety of other information available and is extremely important in planning to

best meet customer needs and provide for a more reliable generation system. The 16.25% minimum

Summer TRM is necessary to ensure the combined summer and winter reserve margins remain at

about the 1:10 LOLE Threshold.

PUBLIC VERSION

A-1

Appendix A – Examining the Need for a Winter Target Reserve Margin

A. Background

The last time that the “System” experienced an outage due to a generation shortfall was on January

17, 1977 – a winter reliability event. Since that time, the System has delivered reliable, low-cost

generation even through some of the coldest weather on record during the mid-1980s. The ability to

maintain reliable service during those extreme periods was primarily because the System’s summer

peaks were significantly higher than the System’s winter peaks in that era as demonstrated in the

figure below.

Figure A. 1. Summer and Winter Historical Peak Demands

PUBLIC VERSION

A-2

In addition to being primarily summer peaking, during the 1990s and 2000s, the System only

experienced one year, 1996, where system-weighted temperature fell below 10ºF. During that same

stretch of time, customer technology and behavior began to change. Emphasis on energy efficiency

and summer demand response programs began to alter the dynamics of customer response to

extreme summer and winter temperatures. That evolving response (at least as it relates to winter) was

never observed due to the absence of the extreme cold-weather events. The streak without extreme

cold weather ended in January 2014 with the Polar Vortex event when system-weighted temperatures

reached 9ºF. The chart below shows the minimum system-weighted temperatures observed on the

System between 1962 and 2015.

Figure A. 2. Historical Minimum System Temperatures

PUBLIC VERSION

A-3

It was the 2014 Polar Vortex event in which this change in load response was first observed. At that

time, the System had a reserve margin of approximately xxx, representing approximately xxxxxxxx of

more reserves in 2014 than what was required by the short-term TRM at that time of 13.5%. Without

these additional reserves the System would have experienced a significant loss of load event during

the 2014 Polar Vortex, which could have been as large as xxxxxxxx. Similarly, the System may have

also experienced such an event in the winter of 2015 but for the approximately xxxxxxxx plus of

reserves above the 13.5% short-term TRM. Between 2014 and 2018, there have been 23 winter-

weather-related operations advisories,15 including 20 times when a Conservative System Operations

(“CSO”) Watch16 advisory was issued, once when the System declared Alert Level 1A,17 once when

the System declared Alert Level EEA1, and once when the System declared Alert Level EEA2.18 By

comparison, during the same period, there have been only three CSO events directly related to

summer peak load conditions.

Even prior to the Polar Vortex event of 2014, operations personnel began expressing concern over

reliability risks during the winter peak period. On August 16, 2011, the Federal Energy Regulatory

Commission (FERC) and the North American Electric Reliability Corporation (NERC) issued a report

and guidance document expressing the need to be concerned with winter reliability issues. That report,

Reliability Guideline: Generating Unit Winter Weather Readiness – Current Industry Practices,19 was

developed after a February 2, 2011 event in ERCOT in which approximately 1.3 million electric

customers did not have service during the winter peak demand of that day. The Operating Companies,

however, had already been performing such assessments beginning in 2007 for the 2008 Winter Peak

Period. Those assessments first began indicating the potential for a reliability concern when the

assessment performed in 2009 for the 2010 winter peak noted “Possible Gas Scheduling Restrictions”

as a challenge. The list of challenges expanded each year forward from that point.

15 Based upon report generated by Southern Balancing Authority Area. 16 A CSO is issued when there is an expectation of high load that warrants extreme caution during operations. 17 A Southern Balancing Authority Area internal “alert” that occurs just prior to NERC Alert Level EEA1. 18 EEA1 and EEA2 are system alert levels defined by the North American Electric Reliability Corporation (“NERC”). 19 Document accessible from NERC at

https://www.nerc.com/comm/OC_Reliability_Guidelines_DL/Generating_Unit_Winter_Weather_Rea

diness_final.pdf.

PUBLIC VERSION

A-4

Currently, there are six primary determinants (discussed in more detail below) that have been identified

as key drivers affecting the winter reliability risk concerns on the System, including

the narrowing of summer and winter weather-normal peak loads,

the distribution of peak loads relative to the norm,

cold-weather-related unit outages,

the penetration of solar resources,

increased reliance on natural gas, and

market purchase availability.

Prior to the 2015 Reserve Margin Study, 20 most of these drivers were unobserved and unmodeled in

the reliability planning model. The 2015 Reserve Margin Study made a first attempt at modeling these

drivers, resulting in an increase in Target Reserve Margin from 15% to 16.25%. Since the 2015

Reserve Margin Study, planners have continued efforts to refine both the modeling assumptions and

the modeling techniques surrounding these drivers. In the process, it has become evident that the

most effective way to plan for and manage these reliability risks is to establish a Winter Target Reserve

Margin.

B. Key Drivers

The six primary drivers affecting the winter reliability risk issue are discussed in the following sections.

B.1 Narrowing of Summer and Winter Weather-Normal Peak Loads

On a weather-normal basis, the System remains a summer peaking utility. However, over the course

of the last 10-15 years, the gap between the weather-normal summer peak load and the weather-

normal winter peak load has narrowed. Figure A. 3 below shows the one-year ahead forecasted peak

loads since 2006 as well as the Budget 2018 forward-looking longer-term forecast. The graph shows

how the gap between the summer and winter weather-normal forecasted peak loads has narrowed

since 2006 from greater than xxxxxxxxxx to less than xxxxxxxxxx.

20 An Economic Study of the System Planning Reserve Margin for the Southern Company System, January 2016.

PUBLIC VERSION

A-5

Because the gap between these peaks has narrowed – and are likely to remain closer in the future –

the System has less flexibility to handle any significant variations in seasonal reliability such as those

described in the remaining sections below. Therefore, it becomes necessary to examine System

performance in the winter independently from the summer through a Winter Target Reserve Margin.

Figure A. 3. Historical Forecasted Weather Normal Peak Loads

B.2 Distribution of Peak Loads Relative to the Norm

As discussed in the Background section above, customer load response has changed such that

response to abnormal weather conditions in the winter is more volatile than the summer. One of the

primary purposes of the TRM is to have the resources necessary to handle these abnormal weather

conditions. In both the summer and the winter, there is a probability distribution around the forecasted

weather-normal peak load. This distribution is determined by the expectation of non-weather-normal

REDACTED

PUBLIC VERSION

A-6

conditions, represented within SERVM21 by the 108 modeled load shapes for the 54 historical weather

years. Figure A. 4 below shows the distribution of the modeled summer and winter non-weather-

normal peak loads about their respected weather-normal peak load forecast. This chart shows that in

the summer the peak load can be either 6.6% higher than the average or 6.8% lower than the average.

In the winter, however, the peak load can as much as 22% higher than the average or 14.4% lower

than the average. The chart also demonstrates that there is a significant possibility that the winter peak

load in any given year can even be higher than the summer peak load.

Figure A. 4. Distribution of Modeled Summer and Winter Peak Loads

21 SERVM is a probabilistic reliability risk evaluation tool used in the Reserve Margin Study and other

reliability analyses.

PUBLIC VERSION

A-7

Of the 108 peak loads modeled in SERVM, there are 23 winter peaks greater than their respective

summer peaks, representing roughly a 20% probability that the winter peak will be higher than the

summer peak in any given year. This is consistent with what has been historically experienced. As

shown in Figure A. 5 below, there have been two out of the last 10 years (2014 and 2015) in which

the actual winter peak was higher than the actual summer peak.

Figure A. 5. Historical Summer and Winter Peak Loads

Note: Figure shows total aggregate load dispatched within the Southern Company Pool.

B.3 Cold-Weather-Related Unit Outages

Extreme cold-weather conditions often result in increased unit outage rates. History has demonstrated

that as temperatures continue to decrease the outage rate tends to increase exponentially. While the

causes (i.e., the components impacted by the cold weather) may be different for each, steam

generators, CCs, and CTs all have vulnerabilities to extreme cold temperatures. Table A. 1 below

shows several historical dates when extreme temperatures have occurred on the system. Many of

PUBLIC VERSION

A-8

these caused significant outages on the system. The table demonstrates that the colder the

temperature, the more likely weather-related outages will occur.

Table A. 1. Historical EFOR During Cold-Weather Events

Date of Event

System Weighted

Temperature (F)

EFOR (% of System

Capacity)

xxxxxxxxx xxxx xxxxxx xxxxxxxxx xxxx xxxxxx

xxxxxxxxx xxxx xxxxxx






















After the 2014 Polar Vortex event, the Operating Companies began implementing measures to

improve the performance of its resources under extreme conditions. Those measures included the

development of Standards of Excellence procedures for preparing generating facilities for cold weather

and the addition of freeze protection on certain vulnerable equipment. System plant performance

experts are confident that these efforts to improve cold-weather performance will ultimately result in a

PUBLIC VERSION

A-9

reduction in cold-weather outages relative to historical trends. However, even with these

improvements, there will always remain an exponentially increasing probability of performance risk as

system-weighted temperatures reach the more extreme cold levels. Figure A. 6 below shows the trend

of the total System outages from Table A. 1. It also shows that same trend adjusted by an assumed

average base EFOR of xx, representing the incremental outage rate associated with cold weather.

Finally, it shows those same incremental outage rates adjusted to reflect the expectation of improved

performance over time.

Figure A. 6. Cold Weather Unit Outage Performance

B.4 Penetration of Solar Resources

While reasonably correlated to summer peak load periods, solar generation is not well correlated to

winter peak load periods, which occur around dawn or dusk. Thus, solar resources contribute

significantly more toward summer reliability than they do toward winter reliability. Therefore, unless

REDACTED

PUBLIC VERSION

A-10

planners are looking at the System from both a summer and winter TRM perspective, the addition of

solar resources can give the false impression of increased overall reliability. If only the Summer TRM

is considered, a significant penetration of solar resources may contribute toward meeting summer

reliability needs but would not contribute significantly toward meeting winter reliability needs, leading

to possible winter reliability concerns. Figure A. 7 below shows the expected penetration of solar

resources on the System through 2021 along with their corresponding Incremental Capacity

Equivalent (“ICE”) summer and winter capacity values.

Figure A. 7. Solar Resource Penetration

This relative seasonal performance of solar resources can be confirmed by observation of actual

historical solar output across the top 20 load hours of the summer and winter peak seasons for the

solar resources currently installed on the System. Figure A. 8 below shows the relative summer and

winter output (as a percentage of nominal installed solar capacity) on the System since 2015 averaged

over the highest 20 load hours in the summer and winter periods. Note that the comparison of the

average output across the top load hours cannot be used to validate or compare with the ICE values

REDACTED

PUBLIC VERSION

A-11

because the two metrics have different meanings, and the historical observations are for only a few

sample years. However, both metrics do indicate solar has significantly different contributions to

reliability in the summer versus the winter, with significantly less in the winter compared to the summer.

Figure A. 8. Solar Output During Highest 20 Load Hours

B.5 Increased Reliance on Natural Gas

Over the last decade, the System has increased its reliance on natural gas as a fuel source to meet

its energy and demand needs. Figure A. 9 below shows the historical and future projected breakdown

of energy by fuel type for the System, demonstrating the increased expectation for reliance on natural

gas. The “coal or gas” slice in the 2027 Projected pie chart indicates uncertainty in coal vs. gas usage

based on uncertainties in the forecasted price of natural gas.

PUBLIC VERSION

A-12

Figure A. 9. Historical and Projected Energy Use by Fuel Type

This increased reliance on natural gas increases exposure to gas delivery constraints, especially

during winter peak conditions, because gas pipelines limit usage to firm transportation contracts.

Figure A. 10 below demonstrates that over the last 6 years (2012 thru 2017), most operational flow

orders22 issued by the two primary pipelines that serve the System have occurred during the winter

months.

22 Operational flow orders are issued by pipeline operators when demand for natural gas causes constraints on the pipeline such that only those holding firm gas transportation contracts can utilize the pipeline.

REDACTED

PUBLIC VERSION

A-13

Figure A. 10. Monthly Distribution of Operational Flow Orders

To model the constraints associated with these operational flow orders, SERVM allows the user to

phase out the availability of interruptible gas transportation based on the minimum and maximum daily

temperature. When no interruptible transportation is available, the model only allows the unit to operate

to the extent it has firm gas transportation or an alternative fuel supply such as on-site fuel storage.

Figure A. 11 below shows the phase-in and phase-out of interruptible gas transportation as modeled

in SERVM.

PUBLIC VERSION

A-14

Figure A. 11. Interruptible Gas Transportation Model

To mitigate the risk against these operational flow orders, the Operating Companies have a Fuel Policy

that requires either on-site backup fuel (such as oil) or the acquisition of firm gas transportation from

the pipeline. For CTs, the policy requires the equivalent of xxxxxxxxxxxxxxx of firm transportation. For

CCs, the policy requires the equivalent of xxxxxxxxxxxxxxxx of firm transportation for base mode

operation and ten hours per day of firm transportation for operation in full pressure modes.

Unfortunately, while this policy is sufficient for typical (i.e., normal) weather conditions, it can be

insufficient for the most extreme weather conditions. As temperatures fall during the more extreme

winter conditions, CTs may need to operate greater than xxxxxxxxxxxxxxx and CCs may need to

operate in full pressure mode more than xxxxxxxxxxxxx. However, if the pipeline has issued an

operational flow order, these resources will not be able to serve load once their firm gas transportation

allocation has been fully utilized, resulting in unit outages during critical times causing either the need

to operate more expensive oil facilities or, in the worst case, loss of load events. Additionally, the

pipeline operators may limit the ability of the CTs to take the nominated natural gas across the

xxxxxxxx and force them to take the natural gas in equal increments across 24 hours, limiting the

ability to use these resources to meet peak load. The Operating Companies continue to evaluate the

risk of such events against the expense of additional firm gas transportation.

REDACTED

PUBLIC VERSION

A-15

B.6 Market Purchase Availability

Traditionally, the reserve margin studies have modeled the regions surrounding the System to

incorporate the availability of economic and reliability purchases from those regions. To avoid bias in

the analysis results and not include purchases that might not be available in the real world, these

regions are generally modeled at or near a reasonable level of reliability – specifically, they are

modeled at or near a Loss of Load Expectation (“LOLE”) of 0.1 days per year. This modeling effort

already results in fewer purchases during the winter than in the summer. This is due primarily to the

fact that when the System experiences very high demands resulting from extreme cold temperatures,

the surrounding regions also experience those extreme temperatures and demands. Figure A. 12

below shows several recent cold-weather events and the amount of purchases that were available to

the System at the time of the event.

Figure A. 12. Historical Purchases During Cold-Weather Events

REDACTED

PUBLIC VERSION

A-16

This kind of purchase availability restriction can occur during extreme summer temperatures as well,

but not to the same degree as in the winter. This creates greater relative market availability risk in the

winter than in the summer, further supporting the need to monitor and review winter reliability

independently from summer. While absolute limits on purchases are not easily modeled within

SERVM, operations personnel did provide purchase availability “targets” (rather than absolute limits)

for use in the 2018 Reserve Margin Study. Those targets were implemented by a combination of sales

price limitations and hurdle rates between regions.

C. Aggregate Impacts of Drivers on Winter Reliability

Over the past several years, significant efforts have been made to model these winter reliability drivers.

The result has been an improvement in the reliability model that more closely matches what has been

seen historically in the operational world. The following demonstrates how the modeling of these key

drivers has impacted winter reliability.

C.1 Total Available Capacity by Season

In updating unit and system assumptions, one of the impacts that has resulted is a reduction in relative

capacity during the winter months as compared to the previous study. In the 2015 Reserve Margin

Study, there was considerably more total available capacity at lower winter temperatures than at

summer temperatures. It is still true that many resources, such as CTs and CCs, have greater capacity

output during cold temperatures than they have during hot temperatures – and were modeled as such

in the 2018 Reserve Margin Study. However, not all resources can be depended upon for that

additional capacity. Several of the CT and CC resources available to the System are Power Purchase

Agreements (“PPA”) that have contractual limitations on the amount of capacity that can be depended

upon on a firm basis. While the resource may be able to produce more during the winter, the System

does not have firm access to that additional capacity and the counterparty may not be obligated to

provide the additional capacity available in the winter. Furthermore, the additional capacity that is

available from other CT and CC resources is offset by the lower capacity contributions of solar and

demand-side resources in the winter relative to summer. Figure A. 13 below shows that there is very

little difference in the available capacity at a System-weighted temperature of 95ºF than there is at

either 40ºF, 20ºF, or even at 10ºF.

PUBLIC VERSION

A-17

Figure A. 13. Total Available Capacity by Temperature

C.2 EUE by Season

Upon modeling these key drivers, the reliability model shows greater probability of EUE in the winter

than has been previously shown. Figure A. 14 below shows the seasonal distribution of EUE at various

(summer-oriented) reserve margins. The chart shows that at very low reserve margins, there is

significant EUE in both the summer and winter periods. As reserve margin increases, the EUE in both

the summer and the winter decreases. However, the EUE decreases much more rapidly in the summer

than in the winter. In the winter, there is a probability of substantial EUE even at higher reserve margin

levels. This is because the most extreme winter conditions in the model, while having a very low

probability of occurrence, have a very high impact on EUE.

PUBLIC VERSION

A-18

Figure A. 14. Seasonal EUE by Reserve Margin

C.3 LOLE by Season

Another way to view the relative risk between summer and winter is through the LOLE. LOLE,

expressed in number of days of outage per year, shows the probability that an EUE event will occur

in any given month or year. Therefore, while the EUE metric shows both the magnitude and probability

of risk, LOLE focuses only on the probability of event, so it is not biased by the occurrence of large

EUE events. The figure below shows the relative LOLE for both summer and winter. This chart

demonstrates that at lower reserve margins, there is a significantly higher probability of a summer-

related event, but at the higher levels, the probability of a winter-related event is greater. Taking Figure

A. 14 and Figure A. 15 together, it can be concluded that the summer-related events are relatively

small in magnitude while the winter-related events are very large in magnitude. Because the

probability of those events remains even at high reserve margins, it becomes necessary to give

particular attention to those winter-related risks.

REDACTED

PUBLIC VERSION

A-19

Figure A. 15. Seasonal LOLE by Reserve Margin

D. The Nature of the Winter Reserve Margin

Traditionally, reserve margins have been stated in terms of summer peak demands and summer

capacity ratings as stated in the following formula:

�� =�� − ��

�� 100%

Where:




REDACTED

PUBLIC VERSION

A-20

This traditional representation is essentially a Summer TRM and has been the only reserve margin

considered because the System (in aggregate) has always been, and remains, summer peaking on a

weather-normal basis. These traditional reserve margins stated in summer terms have historically

been in the 15-17% range.

However, reserve margins can just as easily be stated in alternate terms. In fact, the traditional

Reserve Margin Study is based on an evaluation representing the simulation of an entire year – in fact

thousands of alternative simulations of that one year. When the traditional reserve margin is

calculated, what is being determined is a specific number of megawatts that are needed relative to

peak load. Those megawatts include an underlying existing system (at a 10% reserve margin) and a

certain number of reliability CTs added that represents the minimum total cost across the entire year.

Once that has been established, a reserve margin can be calculated. That reserve margin is

traditionally calculated based on a snapshot of a single hour in that year-long evaluation – the weather-

normal summer peak against the official summer unit ratings. However, there are 8,760 hours in the

case, each representing different load values and different amounts of total capacity because rated

output of the resources in the case changes due to variations in temperature. Therefore, one could

theoretically say there are 8,760 different reserve margins in that case – one for each hour of the year.

Of present interest, however, are just the summer peak and the winter peak. Just as a summer reserve

margin is a snapshot of the summer peak hour against summer capacity ratings, the winter reserve

margin is a snapshot of the winter peak hour against the winter capacity ratings. That winter reserve

margin is represented by the following formula:

�� =�� − ��

�� 100%

Where:




Because winter peak loads are different (lower for a summer peaking utility) than summer peak loads

and because winter generating capacity can be different than summer generating capacity, the Winter

TRM can be higher than the Summer TRM. The extent to which the Winter TRM is higher than the

Summer TRM depends on the relationship between the total available capacity in the summer versus

PUBLIC VERSION

A-21

the total available capacity in the winter as well as the differences in the weather-normal summer and

winter peak loads. It is not out of the question for a Summer TRM of 15% or 16% to have an equivalent

Winter TRM in the mid-to-upper 20s. However, this Winter TRM represents both the same cost

and the same level of reliability as its Summer TRM equivalent – despite the appearances of being

a “higher” reserve margin.

To illustrate this relationship, it is possible to take a snapshot of the System at a given moment in time

and create a waterfall chart that demonstrates how to translate a summer reserve margin into a winter

reserve margin. Figure A. 16 below illustrates this reserve margin translation from summer to winter.

Reading the chart from left to right, a 16.25% summer reserve margin is based on summer total

available capacity and the summer peak load. However, when moving from summer to winter there

are various changes associated with increases or decreases in capacity. This is because some

resources have higher capacity ratings in the winter versus the summer and others have lower

capacity ratings in the winter versus the summer. Finally, there is a difference in the summer peak

load and the winter peak load as well. In the example of Figure A.16, a 16.25% summer reserve margin

is equivalent – that is, it has the same cost and the same level of reliability – to a 24.7% winter reserve

margin.23 In other words, if a Reserve Margin Study indicated the need for a 16.25% summer TRM,

then it likely also indicated the need for a 24.7% TRM in the winter – especially if the study showed

significant EUE potential in the winter.

23 The 24.7% winter equivalent is based on the study case where the system is reduced to a summer reserve margin of 10% and restored to 16.25% using incremental CTs (consistent with how the Reserve Margin Study is performed).

PUBLIC VERSION

A-22

Figure A. 16. Winter Equivalent Waterfall

It should be carefully noted, however, that this waterfall chart is based on a snapshot in time. If

anything changes on the System that changes the relationship between summer and winter, this

equivalency changes.

E. Resulting Need for Winter Target Reserve Margin (“TRM”)

Because the equivalency between summer and winter can change depending upon System

conditions, it would be dangerous to only consider the summer TRM of 16.25% when planning the

System and presume the winter will always have the necessary 24.7%. For example, if a coal unit

were retired and replaced with a CC of equal summer capacity, the winter reserve margin would be

higher than 24.7%. This is because a coal unit has the same ratings for both summer and winter while

a CC may have more capacity in the winter. Similarly, if a CT were retired and replaced with a solar

facility, the winter reserve margin would be lower than 24.7% because the CT has higher capacity in

the winter relative to summer, but a solar facility’s capacity contribution is less in the winter. Likewise,

if the winter peak load forecast increased relative to the summer, the winter reserve margin would be

lower than the 24.7%.

PUBLIC VERSION

A-23

This changing winter equivalency phenomenon can be demonstrated by examining how the winter

equivalent of the currently approved 16.25% TRM (a summer-oriented value) has changed since the

2015 Reserve Margin Study. The 2015 Reserve Margin Study first introduced some of these winter

reliability risks as the reason for the increase in reserve margin at that time from 15% to 16.25%. The

winter equivalent of 16.25% from that study – if it would have been calculated at that time – would

have been 26% for a study year of 2019.24 That reliability case was based upon Budget 2016. When

reliability cases were updated for Budget 2017, the study year was moved to 2024 and the winter

equivalent of 16.25% reduced from 26% to 25.6%.25 When reliability cases were updated for Budget

2018, the study year was moved from 2019 to 2025; and the winter equivalent of 16.25% dropped

again to the 24.7% shown in Figure 16 above. However, that 24.7% is based upon the theoretical

situation in which the System is reduced to 10% and restored to 16.25% using incremental CTs. The

actual winter equivalent of the existing system if it were reduced from its current state down to 16.25%

would only be 23.7%. In other words, if planners only evaluate the system using the 16.25% Summer

TRM, they could be misled into believing the system had adequate reliability in the winter (i.e., the

presumed 26% winter equivalent required by the 2015 Reserve Margin Study) when the reality would

be that the System only had 23.7% in the winter. This could lead to an unexpected and unforeseen

reliability event in the winter such as what happened with the Polar Vortex event of 2014.

The Reserve Margin Study identifies the amount of reserves needed to maintain the proper economic

and reliability balance in both the summer and winter seasons. It is the requirement identified by the

study, not the changing equivalence, that should be considered as part of the planning process. Only

considering the Summer TRM from the study essentially plans to the changing equivalence, not the

requirement identified in the study, which could be misleading. Therefore, it is necessary to calculate

both the Summer TRM and the required Winter TRM and then monitor and plan to both accordingly.

24 This winter equivalent is based on reducing the system to 10% and restored to 16.25% using incremental CTs. 25 This winter equivalent is based on reducing the existing system down to 16.25%; reducing the system to 10% and restoring with incremental CTs would result in a winter equivalent of 26.5%.

PUBLIC VERSION

A-24

F. Conclusion

In conclusion, when the determinants and the resulting impact on seasonal reliability are carefully

considered, continuing to plan the System using only a single (summer-oriented) TRM will increase

the likelihood of an unforeseen loss of load event like the one that occurred in January 1977 and like

what could have happened in January 2014. Therefore, while it may not be possible or cost-effective

to completely eliminate the possibility of a winter loss of load event, it is necessary to establish and

plan the System on a seasonal basis, with both a Summer TRM and a Winter TRM, to provide the

appropriate level of mitigation against such risks.

PUBLIC VERSION

B-1

Appendix B – Capacity Worth Factors

A. Background

Capacity Worth Factors (“CWFs”) represent the relative worth of capacity from one period to another

(i.e., hour, month, season, etc.). As such, they represent the relative risk of a reliability event from one

period to another. CWFs are developed hourly using the SERVM reliability model and from that model,

represent the hourly improvement in reliability associated with a “perfect” megawatt (i.e., a megawatt

that is available every hour of the year). CWFs can be represented hourly or they can be aggregated

and represented monthly or even seasonally. CWFs are calculated at the Target Reserve Margin and

so are a downstream output of the Reserve Margin Study and the associated approved Target

Reserve Margin.

CWFs in some form are used in almost all System-wide analyses when deriving capacity value,

including:

IIC reserve sharing,

PRICEM analyses,

Retirement studies,

Power Purchase Agreements,

ICE Factors for the IRP, and

Renewable Cost Benefit Analyses.

B. The SERVM Reliability Cost Report

The Capacity Worth Factor Table (“CWFT”) is derived from the Reliability Cost report produced by the

SERVM model. The Reliability Cost report generates the weighted sum of:

(a) the cost of EUE, plus

(b) the cost of expected Reliability Purchases, plus

(c) the cost of any Spinning, Supplemental, or Regulating Reserve shortfall.

Unlike the Reserve Margin Study, when calculating the CWFT, the Company is not interested in cost

impacts, but rather in reliability impacts. Therefore, the CWFT is calculated only considering the

PUBLIC VERSION

B-2

probability and magnitude (not cost), resulting in a MW-weighting of the potential events identified

above. To accomplish this, these events are all modeled with equal costs so that the Reliability Cost

report is effectively only weighting these components based on MW impact, not relative cost, using

the following modeling techniques:

Reliability Purchases (defined as any purchase that avoids EUE) are determined by running

the SERVM simulation as a “Southern-Only” case; this eliminates the model’s ability to make

reliability purchases which, in effect, treats Reliability Purchases as EUE.

Spinning, Supplemental, and Regulating Reserves are modeled such that load will be

curtailed to prevent a shortfall, thus also valuing those shortfalls as EUE.

Figure B.1 below shows all reliability components and which ones are included in the Reliability Cost

report as inputs into the CWFT calculation.

Figure B. 1 Treatment of Reliability Components in the CWFT Calculation

The Reliability Cost report can be generated using a combination of EUE Capacity, EUE IntraHour,

EUE MultiHour, Net Purchases, and Production Cost. To generate the appropriate CWFT using this

PUBLIC VERSION

B-3

methodology, the Reliability Cost report is generated using EUE Capacity, EUE Intra-Hour, and EUE

Multi-Hour (not Net Purchases and not Production Cost).

C. Capacity Worth Factor Results

CWFs are updated with each budget cycle. The 2018 Reserve Margin Study was performed using

Budget 2018 (“B2018”) vintage data for inclusion in the 2019 IRP. CWFs resulting from the 2018

Reserve Margin Study will not be officially available until after the Budget 2019 (“B2019”) Reliability

Base Case has been developed and so should be available in the first quarter of 2019. However, a

12x24 representation of the CWFs associated with the B2018 vintage data are shown in Tables B.1

and B.2 below.

Table B.1 shows the CWFT assuming the currently approved 16.25% TRM without Seasonal Planning.

Table B. 1 B2018 Vintage CWFT at 16.25% Summer TRM (Central Prevailing Time)

REDACTED

PUBLIC VERSION

B-4

Table B-2 shows the B2018 Vintage CWFT assuming the approval of the proposed 26% Winter TRM.

Table B. 2 B2018 Vintage CWFT at 26% Winter TRM (Central Prevailing Time)

These tables will change once the Reliability Base Case has been updated for B2019 vintage planning

assumptions. Furthermore, Table B-2 should be considered preliminary and indicative only. Table B-

2 as shown above has not been used for the purposes of evaluating any renewable resource or any

other resources.

Because the 26% Winter TRM is the dominant factor for System reliability, upon approval of seasonal

planning, the official CWFT for the System will be the CWFT associated with the 26% Winter TRM.

REDACTED

PUBLIC VERSION

1 | P a g e


ALABAMA POWER COMPANY ) PETITION )

Petitioner ) ) Docket No. ________

DIRECT TESTIMONY OF MICHAEL A. BUSH ON BEHALF OF ALABAMA POWER COMPANY

I. INTRODUCTION


A. My name is Michael A. Bush. I am the Manager of Generation Planning and 2

Development for Southern Company Services, Inc. (“SCS”). My business address is 600 3

North 18th Street, Birmingham, Alabama 35203. 4

Q: DESCRIBE YOUR PROFESSIONAL BACKGROUND. 5

A: I graduated from Auburn University with a degree in Electrical Engineering in 1987. 6

After working outside the Southern Company for a brief period, I joined Mississippi 7

Power Company in 1990 (having worked there as a cooperative student while at Auburn). 8

I remained at Mississippi Power until 1995, at which time I transferred to SCS in 9

Birmingham, Alabama to work in the wholesale marketing organization. In 1996, I 10

became a wholesale electricity term trader and in 1999 I was appointed Manager of 11

Energy Trading. In 2003, I took the position of Director of Portfolio Management, and in 12

2009, I moved to my current role as Manager of Generation Planning and Development 13

(“GPD”). 14

Q: WHAT ROLE DOES SCS SERVE RELATIVE TO ALABAMA POWER 15

COMPANY? 16

PUBLIC VERSION

2 | P a g e

A: SCS is a centralized service company that provides various services to Alabama Power 1

and other operating companies on the Southern Company system at their direction and at 2

cost. These services include, but are not limited to, accounting, contract administration, 3

engineering, and fuel procurement, as well as the services provided by GPD. 4

Q: DESCRIBE YOUR PROFESSIONAL DUTIES AND RESPONSIBILITIES AS 5

MANAGER OF GPD. 6

A: I hold primary responsibility for all of the generation planning and development services 7

provided by GPD. These services include supply side technology evaluations and 8

integration, asset valuation, asset acquisition, project development and asset 9

implementation for the retail operating companies. 10





generation resources. These resources have been identified by Alabama Power as 15

necessary and appropriate additions to its existing generation fleet, in order to continue to 16

serve reliably the electricity demands of its customers. One of those resources is a new 17

combined cycle gas turbine (“CCGT”) facility at the Company’s existing Plant Barry. 18

The purpose of my testimony is to provide additional details regarding this facility, which 19

I will refer to as Barry Unit 8, including the manner by which it would be delivered to the 20

Alabama Power system. I will also overview the process that led to its identification as a 21

cost-effective generation resource option for Alabama Power and its customers. 22

Q: WOULD YOU PLEASE SUMMARIZE YOUR TESTIMONY? 23

PUBLIC VERSION

3 | P a g e

A: In Part II of my testimony, I provide a high-level technical overview of Barry Unit 8, 1

including its fundamental design parameters and operating characteristics. In Part III, I 2

discuss the manner by which Barry Unit 8 will be constructed and placed into service, if 3

the APSC grants Alabama Power a certificate of convenience and necessity for the 4

facility. As part of this discussion, I provide context for the turnkey Agreement for 5

Engineering, Procurement and Construction (“EPC Agreement”) that Alabama Power, by 6

and through SCS acting as its agent, has entered into with Mitsubishi Hitachi Power 7

Systems Americas, Inc. (“MHPS”) and Black & Veatch Construction, Inc. (“B&V”). 8

Although the EPC Agreement itself is a complex collection of documents and materials, 9

at its essence the agreement provides for the turnkey delivery of a new generating facility 10

by MHPS and B&V by November 1, 2023. In Part IV, I discuss the process that gave 11

rise to the execution of the EPC Agreement, including the manner by which the 12

appropriateness of the turnkey option as a potential resource addition for Alabama Power 13

was determined. Part V of my testimony provides concluding remarks. 14

II. BARRY UNIT 8 15

Q: DESCRIBE BARRY UNIT 8. 16

A: Barry Unit 8 will provide approximately 726 MW (nominal/winter) of CCGT generating 17

capacity at the initial commercial operation date. Following a post-48 month uprate, the 18

unit will have a winter capacity of 743 MW. The principal components of Barry Unit 8 19

include one Mitsubishi 501 J-series air-cooled combustion turbine, one heat recovery 20

steam generator with duct firing, and one condensing reheat steam turbine (together 21

comprising a 1-on-1 combined cycle configuration), along with other balance of plant 22

equipment, including a cooling tower for closed-cycle cooling operations. The unit is 23

PUBLIC VERSION

4 | P a g e

expected to have an average heat rate of 6,210 Btu/kWh, and an expected useful life of 40 1

years. 2

Q. WHAT IS THE EXPECTED ANNUAL OUTPUT OF BARRY UNIT 8? 3

A: Again, the expected winter output of the unit at delivery is 726 MW (at ambient 4

conditions of 28ºF and 68 percent relative humidity). The expected summer output at 5

delivery is 653 MW (at ambient conditions of 94ºF and 47 percent relative humidity). As 6

the seasonal differential implies, variable conditions, such as ambient temperature, 7

relative humidity, Btu content of natural gas delivered to the unit, and other factors, will 8

affect actual unit capability. Following a scheduled uprate after the unit has been in 9

operation for 48 months, the winter and summer capacities will be 743 MW and 685 10

MW, respectively. While minimal deviation may occur, MHPS and B&V must remedy 11

any material deviation. Later in my testimony I discuss how the EPC Agreement 12

provides for these assurances. 13

Q: WHAT ARE THE ADVANTAGES OF CCGT TECHNOLOGY? 14

A: As reflected in Alabama Power’s integrated resource plan (discussed in the testimony of 15

Mr. Kelley), CCGT technology has been identified as one of the candidate technologies 16

to meet the Company’s incremental capacity and energy needs. CCGT is a proven means 17

for utilities to reliably and cost-effectively satisfy the electricity needs of their customers. 18

The generators are highly efficient at converting fuel to electric power, and offer a 19

significant degree of flexibility, in terms of following swings in system load and 20

responding quickly to system dispatch signals. At present, there are approximately 260 21

gigawatts of installed CCGT capacity in the United States. 22

Q: DOES ALABAMA POWER HAVE EXPERIENCE OPERATING A CCGT? 23

PUBLIC VERSION

5 | P a g e

A: Yes. Plant Barry Units 6 and 7 are CCGT technology and have been in service for nearly 1

20 years. Note too that Alabama Power generating facilities are dispatched as part of the 2

larger Southern pool, with SCS serving as the agent for the Southern operating companies 3

in the execution of unit commitment and dispatch responsibilities. At present, the pool 4

controls the dispatch of 13 CCGT facilities consisting of 22 units across the entire 5

Southern system. 6

Q: IS THE J-SERIES DESIGN A PROVEN TECHNOLOGY? 7

A: Yes. CCGT technology has been employed for decades, and MHPS’s gas turbine reflects 8

design characteristics originally adopted in the 1970s. The J-series design itself has been 9

deployed in 39 units worldwide with more than 800,000 operating hours logged. The J-10

series with air cooling represents an evolution of earlier MHPS technologies, through the 11

integration of air cooling for combustors instead of steam cooling. At present, five air 12

cooled J-series units are in operation, with more than 19,000 operating hours logged. I 13

would also note that MHPS plays a key role throughout its production process, from 14

development, design and manufacturing, to testing and commissioning, to post-15

deployment servicing. Indeed, in advance of commercial deployment, MHPS operates 16

new designs at an actual load-serving test facility in Japan, in order to verify the systems 17

through practical application. 18

Q: WHERE AT PLANT BARRY WILL THE NEW UNIT BE LOCATED? 19

A: Barry Unit 8 will be sited south of Units 6 and 7, which facilitates the use of existing 20

infrastructure, including natural gas, electric transmission, and water facilities, as well as 21

civil infrastructure (e.g., rail, barge and highway). Plant Barry itself is located in Bucks, 22

Alabama. 23

PUBLIC VERSION

6 | P a g e

Q: WILL NEW INFRASTRUCTURE BE REQUIRED TO ACCOMMODATE 1

BARRY UNIT 8? 2

A: Certain new infrastructure will be required, including: a new tie line to the existing 3

adjacent Ellicott 230 kV substation; a gas extension line from the existing Plant Barry gas 4

yard to the location of the new unit; new water lines; and a new access road connecting 5

two existing plant roads. 6

Q: WILL THE OPERATION OF BARRY UNIT 8 AFFECT THE OPERATIONS OF 7

ANY OF THE OTHER PLANT BARRY UNITS? 8

A: No. All remaining units can continue operating during the construction of Barry Unit 8 9

and after it is placed into service. 10

III. THE EPC AGREEMENT 11

Q: PLEASE EXPLAIN HOW ALABAMA POWER PROPOSES TO CONSTRUCT 12

BARRY UNIT 8. 13

A. Alabama Power is proposing that Barry Unit 8 be constructed by MHPS and B&V in 14

accordance with the EPC Agreement that the Company has entered into with those 15

parties. The EPC Agreement comprises a number of contract documents, including 16

specifications and schedules that are referenced in the agreement itself. Key portions of 17

the EPC Agreement are included with my testimony at Exhibit MAB-1. Under the EPC 18

Agreement, MHPS and B&V will serve jointly and severally as the contractor for the 19

project. I would observe that the EPC Agreement does provide an option for a second 20

unit. Alabama Power has determined, however, to request certification only of a single 21

unit (i.e., Barry Unit 8). The process utilized by Alabama Power to determine the 22

appropriate and cost-effective composition of new generation capacity reflected in the 23

PUBLIC VERSION

7 | P a g e

Company’s petition for a certificate of convenience and necessity is discussed more fully 1

in the testimony of Messrs. Kelley and Looney. 2

Q: WHAT ARE THE KEY MILESTONES FOR CONSTRUCTION OF BARRY 3

UNIT 8? 4

A: Like most projects of this type, the EPC Agreement specifies certain stages at which a 5

prescribed degree of facility design and construction has been completed. These include 6

the contract execution, limited and final notices to proceed, receipt of permits, full 7

mobilization, mechanical completion and substantial completion. Importantly, the EPC 8

Agreement specifies a “Guaranteed Substantial Completion Date” for Barry Unit 8 of 9

November 1, 2023. By that date, MHPS and B&V must, among other things, have 10

completed construction activities at the unit such that it is capable of demonstrating 11

specified performance guarantees. Other specific milestone dates include: a limited 12

notice to proceed by March 2020 for engineering and design; full notice to proceed on the 13

project by November 1, 2020; full site mobilization by May 1, 2021; and the availability 14

of auxiliary power for the facility by December 2022. 15

Q: HAS ANY WORK COMMENCED ON THE PROJECT ALREADY? 16

A: Yes. In order to fully implement the EPC Agreement and to ensure sufficient time to 17

meet the November 1, 2023 Guaranteed Substantial Completion Date, some limited site 18

investigation has commenced. In addition the EPC Agreement contemplates the 19

commencement later this year of certain work on external infrastructure (e.g., the plant 20

access road I noted earlier). 21

Q: WHAT ROLE WILL ALABAMA POWER HAVE DURING CONSTRUCTION 22

OF THE UNIT? 23

PUBLIC VERSION

8 | P a g e

A: Given the size of the project and the fact that it will be taking place at an operating 1

generating facility, Alabama Power and SCS will maintain personnel on site to 2

coordinate the activities of MHPS and B&V with ongoing operations and to confirm the 3

project is proceeding according to the baseline schedule. 4

Q: WHAT IS THE ESTIMATED COST OF THE PROJECT? 5

A: The estimated in-service cost of the project is approximately , which 6

includes costs related both to the EPC Agreement as well as costs associated with 7

Alabama Power’s ownership and management of the project (along with pre-delivery 8

O&M and start-up costs and a management contingency reserve). 9

Q: CAN YOU FURTHER DELINEATE THE TYPES OF COST COMPONENTS 10

WITHIN THE FIRST CATEGORY OF COSTS? 11

A: The EPC Agreement costs are those contemplated by the agreement between the 12

Company and MHPS and B&V, which will be billed to the Company upon completion of 13

the various milestones set forth in the agreement. These costs include: 14

• Engineered equipment, such as the J-series combustion turbine generator, the 15 steam turbine generator, the heat recovery steam generator, and boiler feed 16 pumps; 17

• Engineering and construction management services, including design, 18 development and procurement, project controls, and scheduling; 19

• Design and construction of certain external infrastructure, including roads, water 20 and gas lines, and pump structures; 21

• Supervisory and administrative staffs at the construction site; 22

• Subcontractors and craft laborers (such as welders, electricians and pipefitters); 23

• Construction materials (such as copper, steel and concrete) used by the 24 contractors and their subcontractors; 25

• Indirect construction costs (such as scaffolding and safety equipment); 26

• Sales and use taxes incurred by MHPS and B&V; and 27

PUBLIC VERSION

9 | P a g e

• Labor- and materials-related costs associated with start-up and commissioning of 1 the unit. 2

Q: WHAT COST COMPONENTS ARE INCLUDED WITHIN THE CATEGORY OF 3

OWNERSHIP- AND MANAGEMENT-RELATED COSTS? 4

A: The cost components that I reference here include: 5

• Company and SCS project management, including costs associated with project 6 management, conceptual and detailed design review, project monitoring, and 7 environmental permitting; 8

• Transmission-related infrastructure costs associated with the design and 9 construction of facilities required to integrate Barry Unit 8 into the existing 10 electric system; 11

• Project contingency, which reflects a general estimate of of the total 12 project cost to allow for presently unknown or unidentified circumstances that 13 could affect the cost of the project; 14

• Project financing costs over the course of construction; and 15

• Pre-commercial operating date start-up costs, including fuel- and labor-related 16 costs. 17

Q: DO YOU BELIEVE THIS ESTIMATE REASONABLY REFLECTS THE 18

ULTIMATE COST OF THE PROJECT? 19

A: Yes. The EPC Agreement affords a significant level of certainty, insofar as the ultimate 20

cost of the project is concerned. The EPC Agreement is a fixed-price turnkey agreement, 21

and as I explain more fully below, represents the outcome of a process that saw multiple 22

contractor consortiums (including MHPS and B&V) compete for the opportunity to 23

deliver a new CCGT to Alabama Power. Throughout the process that led to the eventual 24

execution of the EPC Agreement, GPD and others acting at its direction worked 25

extensively to inform the scope of work applicable to the development of a new CCGT at 26

Plant Barry. These efforts were intended to reduce the potential for change orders that 27

might result in material cost increases. 28

PUBLIC VERSION

10 | P a g e

Q: WHAT ASPECTS OF THE CONSTRUCTION PRICE ARE SUBJECT TO 1

CHANGE? 2

A: While price certainty is the goal of the turnkey contract, the price for the construction of 3

Barry Unit 8 is not fixed in absolute terms. First, the ownership- and management-4

related costs are a function of the construction oversight activities that prove necessary to 5

deliver the unit in accordance with the EPC Agreement. As for activities under the EPC 6

Agreement, there is the prospect for a change event, which is a prerequisite under the 7

agreement for a change order. The EPC Agreement limits the opportunities for change 8

events, as I explain below. More importantly, MHPS and B&V are only entitled to a 9

change in the price or an extension in the time to perform upon demonstration that the 10

change event will have a direct, material, adverse and demonstrable impact on their 11

ability to perform the work under the agreement for the stated price and within the 12

specified time. In addition, MHPS and B&V are obligated to undertake commercially 13

reasonable efforts to mitigate the effects of any change event prior to any change in price 14

being allowed. 15

Q: WHAT CIRCUMSTANCES MAY GIVE RISE TO A CHANGE EVENT? 16

A: Under the EPC Agreement, change events are limited to those changes to the project 17

directed by Alabama Power; an excusable delay that is caused by Alabama Power or an 18

event of force majeure; the discovery of an unforeseen site condition; a change in law; 19

and certain other discrete circumstances that are enumerated specifically in the EPC 20

Agreement (e.g., damage to materials or equipment on site due to force majeure or 21

wrongful acts of Alabama Power; the identification of unanticipated subsurface 22

conditions). In short, matters that are beyond the control of MHPS, B&V, or their 23

PUBLIC VERSION

11 | P a g e

subcontractors can give rise to a change event—but only upon satisfaction of the detailed 1

preconditions set forth in the EPC Agreement can such a change event give rise to a 2

change order and a potential modification of the price for the project or the schedule for 3

its development and commissioning. 4

Q: EARLIER YOU REFERENCED PERFORMANCE GUARANTEES. CAN YOU 5

EXPAND ON THOSE CONTRACT CRITERIA? 6

A: Under the EPC Agreement, MHPS and B&V must deliver a facility with a net output of 7

726 MW at 28ºF in the winter, a net output of 600 MW at 94ºF in the summer, and an 8

average annual heat rate of Btu/kWh. If the actual output of the unit is within 9

percent and the actual heat rate is within percent of the guaranteed performance 10

levels (and certain other guarantees are met), then MHPS and B&V have the option to 11

perform additional work to reach the guaranteed performance levels or pay liquidated 12

damages relative to the difference between the guaranteed and the actual performance 13

levels in order to achieve substantial completion. I would emphasize that until the unit 14

reaches the minimum performance levels, it cannot be deemed substantially complete. 15

After approximately 48 months of operation time, MHPS has committed to perform an 16

uprate on the facility. While precise output levels will ultimately depend on unit 17

operation at the time of the uprate, it is expected that upon completion the unit will have a 18

demonstrated winter capacity rating of 743 MW and a demonstrated summer capacity 19

rating of 685 MW. 20

Q: ARE THERE OTHER GUARANTEES IN THE CONTRACT? 21

A: Yes. In connection with the performance guarantees just discussed, MHPS and B&V 22

must deliver a project that meets specified emissions levels and noise levels. The EPC 23

PUBLIC VERSION

12 | P a g e

Agreement also requires the facility to meet certain reliability guarantees. Specifically, 1

for each of the following substantial completion, the equivalent 2

forced outage rate (“EFOR”) at Barry Unit 8 cannot exceed percent for the 3

combined months of January, February, June, July and August (i.e., months 4

corresponding to the expected winter and summer peaks). In addition, the annual EFOR 5

cannot exceed percent. For clarity, EFOR under the EPC Agreement covers forced 6

outages and unit derates not otherwise caused by Alabama Power’s failure to operate and 7

maintain the facility in accordance with manufacturer’s guidelines. 8

In addition, the EPC Agreement provides for 9

10

11

12

13

14

15

16

17

18

19

Q: EARLIER YOU STATED THAT MHPS AND B&V WILL BE ACTING JOINTLY 20

AND SEVERALLY. WHAT IS THE SIGNIFICANCE OF THIS DESIGNATION? 21

A: I believe this is one of the more unique aspects about the EPC Agreement. Alabama 22

Power has been able to secure the services of an experienced, large project contractor 23

PUBLIC VERSION

13 | P a g e

(i.e., B&V) as well as the original equipment manufacturer (“OEM”) itself (i.e., MHPS) 1

jointly and severally as the designated contractor for design, procurement and 2

construction of the entire unit. This arrangement provides enhanced protection for 3

Alabama Power and its customers against liabilities that may arise in the unlikely event 4

of a failure of performance. In other words, Alabama Power is able to look to either or 5

both of the parties for satisfaction of all obligations assumed individually and collectively 6

by them under the EPC Agreement. In addition, fulfillment of these joint and several 7

obligations is backed by parent guarantees for both MHPS and B&V. 8

Q: ARE THERE OTHER FEATURES OF THE EPC AGREEMENT THAT SERVE 9

TO MITIGATE RISKS TO ALABAMA POWER AND ITS CUSTOMERS? 10

A: As I explain below, the process that led to the execution of the EPC Agreement produced 11

an arrangement that provides very favorable conditions to Alabama Power. Moreover, 12

this process provided Alabama Power the opportunity to simultaneously negotiate and 13

secure a long term service agreement (“LTSA”) for Barry Unit 8. By securing the LTSA 14

terms and conditions in advance of construction, Alabama Power was able to obtain 15

competitive pricing considerations for services necessary for the long-term reliability of 16

the unit. 17

IV. PROCESS FOR EPC AGREEMENT DEVELOPMENT AND EXECUTION 18

Q: DESCRIBE THE PROCESS THAT LED TO THE EXECUTION OF THE EPC 19

AGREEMENT. 20

A: As I mentioned at the outset, GPD continuously investigates the availability of resources 21

that the Southern operating companies might wish to consider as an option to meet the 22

future needs of their customers. In connection with such efforts, GPD was approached in 23

PUBLIC VERSION

14 | P a g e

2016 by the power generation division of a major OEM with a concept to provide a 1

CCGT facility on a fixed-price turnkey basis. 2

Q: HOW DID YOU REACT TO THE PROPOSAL? 3

A: GPD saw upside in the proposal, particularly insofar as a fixed-price project could serve 4

to mitigate risks inherent in the construction of a large-scale, long-lead time project like a 5

new generation facility. Also, over the course of preliminary review of the concept, it 6

became evident that seasonal planning considerations by Alabama Power could create a 7

need for the addition of new generation capacity closely coinciding with the amount of 8

time required to deliver a new CCGT facility (accounting for the necessary regulatory 9

authorizations, as well as design, construction and commissioning). GPD and Alabama 10

Power concluded, however, that a market solicitation of all major and internally approved 11

OEMs had the potential to yield an even more competitive turnkey proposal. 12

Accordingly, in early 2018, SCS solicited proposals on behalf of Alabama Power for the 13

fixed-price delivery of a single turnkey CCGT unit at Plant Barry. 14

Q: WHAT ENTITIES RECEIVED THE SOLICITATION? 15

A: As I noted, the entities solicited included the major OEMs whose CCGT technology 16

designs had been approved for deployment on the Southern system. 17

Q: WHY DID THE SOLICITATION CALL FOR PROPOSALS FOR A NEW UNIT 18

AT PLANT BARRY? 19

A: Alabama Power has several candidate sites for future generation deployment, but Plant 20

Barry was selected based on the anticipated cost savings associated with its ability to 21

accommodate new unit construction and its ability to leverage existing infrastructure, 22

including natural gas transportation capacity. 23

PUBLIC VERSION

15 | P a g e

Q: DID THE SOLICITATION PROVIDE EXTENSIVE DETAILS REGARDING 1

ALABAMA POWER’S EXPECTATIONS FOR THE PROPOSAL? 2

A: As the dedicated supplier of retail electric service to more than 1.4 million customers, 3

Alabama Power has expectations regarding reliability of the systems used to fulfill that 4

responsibility. Moreover, for a new generating unit to be sited at an existing, operating 5

plant, a number of accommodations and protections also would have to be factored into 6

any final agreement for engineering, procurement and construction. So to that extent, the 7

proposal was prescriptive, and included a number of minimum operating, reliability and 8

safety parameters appropriate for the commissioning of a generation facility at the Plant 9

Barry site. However, in recognition of the experience and knowledge held by the OEMs, 10

Alabama Power and SCS encouraged bidders to propose projects they believed would 11

best suit the indicated needs and that OEMs believed most competitive. 12

Q: CAN YOU DESCRIBE THE SOLICITATION PROCESS? 13

A: The solicitation itself was issued in January of 2018, with final proposals received in 14

August of 2018. In between the solicitation and response, the process underwent some 15

evolution, which contributed to its duration. Initially, the solicitation contemplated the 16

OEM serving as contractor under the EPC Agreement. Shortly after proposals were 17

released, SCS and Alabama Power received inquiries as to their willingness to entertain a 18

“consortium” response that included both the OEM and a more traditional construction 19

service provider. Alabama Power saw value in such an approach, if the consortium 20

partners agreed to joint and several liability under the EPC Agreement, as it not only 21

retained the OEM as the primary party for the project, but also expanded responsibility to 22

a second party, namely a proven contractor whose services likely would have been 23

PUBLIC VERSION

16 | P a g e

engaged on a subcontract basis upon issuance of any award. Each of the OEMs agreed to 1

the joint and several construct and paired with a construction partner. Thereafter, SCS 2

separately worked with each of the consortiums to answer technical questions informing 3

their respective proposals. 4

Significant time also was spent with each consortium to negotiate the EPC 5

Agreement that would be submitted with the proposal. Each consortium retained the 6

option to tailor its proposal, with the understanding that material differences would be 7

factored into the risk adjusted evaluation of the proposal. SCS also worked with each 8

consortium on an LTSA for the project. As I mentioned earlier, there was significant 9

value in securing the terms and conditions of the LTSA at this stage of project 10

development, with the respective consortiums competing against one another. 11

Developing the terms and conditions of these documents also contributed to the duration 12

of the solicitation process. 13

Q: HOW WERE THE PROPOSALS EVALUATED? 14

A: The relative merits of the three proposals were considered against each other on a risk 15

adjusted basis. In addition, the proposals were evaluated against the estimated cost of an 16

internally developed self-build project at Plant Barry. The results of the evaluation 17

demonstrated that the most cost-effective option, and one that included the myriad of risk 18

mitigation features that I have discussed in my testimony, was the proposal by MHPS and 19

B&V. 20

Following this determination, a preliminary award letter was delivered to MHPS 21

and B&V by Alabama Power in November of 2018. The award letter recognized that a 22

final determination to proceed with the proposal remained within the discretion of 23

PUBLIC VERSION

17 | P a g e

Alabama Power. The reason for this reservation was twofold. First, the proposal still 1

required consideration alongside other resource opportunities available to Alabama 2

Power, to ensure that it represented a competitive cost-effective resource option. Second, 3

a certificate of convenience and necessity would be required for Alabama Power to 4

proceed fully under the EPC Agreement. 5

Q: WHEN WAS THE EPC AGREEMENT EXECUTED? 6

A: The agreement was executed in May 2019. 7

Q: WHAT CONTRIBUTED TO THE PASSAGE OF TIME BETWEEN THE 8

PRELIMINARY AWARD LETTER AND THE EXECUTION OF THE EPC 9

AGREEMENT? 10

A: During the solicitation, unrelated efforts were ongoing to update the labor agreement 11

applicable to projects on the Southern system. After the preliminary award letter was 12

issued to MHPS and B&V, that labor agreement was finalized. Thereafter, efforts were 13

pursued with these parties to ensure that the EPC Agreement reflected the appropriate 14

labor-related considerations arising out of the Southern system labor agreement. In 15

addition, by that time, SCS and Alabama Power had gained a clearer understanding of 16

what Alabama Power’s capacity needs would be across the relevant time horizon. 17

Accordingly, MHPS and B&V were asked to submit a proposal for the delivery of an 18

optional second CCGT unit at Plant Barry. Lastly, MHPS and B&V were asked to 19

include as part of this submittal a proposal to perform certain external infrastructure 20

work. These factors contributed to the additional months needed to finalize and execute 21

the EPC Agreement. 22

23

PUBLIC VERSION

18 | P a g e

V. CONCLUSION 1

Q: DO YOU HAVE ANY CLOSING REMARKS? 2

A: Yes. As the foregoing discussion demonstrates, Barry Unit 8 represents a unique 3

opportunity for Alabama Power to secure the addition of reliable, cost-effective capacity, 4

in furtherance of its obligations to its customers. The EPC Agreement governing the 5

design, construction and commissioning of Barry Unit 8 contains a number of features 6

that are intended to shift the risks inherent in a project of this kind, thereby protecting 7

Alabama Power and its customers and facilitating the commissioning of this resource in a 8

timely manner. 9


A: Yes. 11

PUBLIC VERSION

PUBLIC VERSION

Direct Testimony of Michael A. Bush

Exhibit MAB-1


PUBLIC VERSION

1 | P a g e


ALABAMA POWER COMPANY ) PETITION ) Petitioner ) ) Docket No. ________

DIRECT TESTIMONY OF M. BRANDON LOONEY ON BEHALF OF ALABAMA POWER COMPANY


A. My name is M. Brandon Looney. I am the Manager of Reliability and Resource 2

Procurement for Southern Company Services, Inc. (“SCS”). My business address is 600 3

North 18th Street, Birmingham, Alabama 35203. 4

Q: PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND 5

PROFESSIONAL EXPERIENCE. 6

A: I graduated from the University of Alabama with a degree in Mechanical Engineering in 7

2003, and received a Master of Business Administration degree from the University of 8

Alabama in Birmingham in 2007. I am also a licensed Professional Engineer in the State 9

of Alabama. I began my career with Southern Company in 2003 in the Engineering and 10

Construction Services organization, working primarily on emissions control equipment. 11

In 2007, I moved to Research and Environmental Affairs, where I focused primarily on 12

technology solutions for the Mercury and Air Toxics rule. In 2012, I became the 13

manager of the Emissions Control Research department. In 2013, I moved to the System 14

Planning organization, where I have held several leadership roles in the areas of Asset 15

Management, Renewable Development, and Environmental and Asset Planning. My 16

2 | P a g e

current role of Manager of Reliability and Resource Procurement is also within that 1

organization. 2

Q: WHAT ARE YOUR RESPONSIBILITIES AS MANAGER OF RELIABILITY 3

AND RESOURCE PROCUREMENT? 4

A: I am primarily responsible for system reliability studies involving generation resource 5

adequacy and support of the retail operating companies in their procurement activities 6

related to generation resources. These efforts include structuring requests for proposals 7

(“RFPs”), developing and negotiating contracts, and evaluating responses to RFPs. 8





generation resources. As reflected in the testimonies of Messrs. Kelley and Bush, 13

Alabama Power had a number of resource options to consider in determining an optimal 14

solution for meeting its supply obligations to customers, including the construction of 15

new generation facilities, the acquisition of existing generation facilities, and the entry 16

into purchase power arrangements (“PPA”). My department worked with Alabama 17

Power personnel to develop economic analyses of the competing resource options under 18

consideration. The purpose of my testimony is to explain that process and the 19

conclusions it yielded. 20

Q: DID ALABAMA POWER ASSIST WITH YOUR EVALUATION? 21

A: Yes. As Mr. Kelley discusses in his testimony, Alabama Power conducted the RFP 22

process soliciting potential capacity offerings from wholesale market participants. 23

3 | P a g e

Among other things, it called for respondents to provide their proposals in a particular 1

format, with generation resource ratings, operating characteristics, price and other 2

relevant components of each proposal individually identified, and regardless of whether 3

the respondent was proposing a PPA or an acquisition. This structure enabled my 4

department to more readily evaluate the pertinent economic characteristics of the various 5

proposals. 6

After receiving the bid proposals submitted in response to the RFP, Alabama 7

Power first undertook a preliminary screen to identify any proposals that did not 8

fundamentally comply with the RFP requirements. Alabama Power then supplied the 9

compliant RFP bid proposals to my group, along with the turnkey proposal for Barry Unit 10

8, for detailed analysis. Forecasting and Resource Planning handled the economic 11

evaluation of projects involving solar with battery energy storage systems (“Solar 12

BESS”), doing so in a manner comparable to the analysis performed by my department. 13

Those results were provided to my department for incorporation into the evaluation and 14

ranking of all the resource options. 15

Q. PLEASE DESCRIBE THE PROCESS UTILIZED BY YOUR DEPARTMENT TO 16

EVALUATE THE PROPOSALS. 17

A. The first step was the development of a reference case, which reflects the operation of the 18

existing system (together with generic resource additions) over a 40-year evaluation 19

period. 20

Q: WHY WAS 40 YEARS USED FOR THE EVALUATION PERIOD? 21

4 | P a g e

A: To conduct an analysis that includes proposals of varying unit lives and term lengths, it is 1

necessary to set an evaluation period that encompasses the longest-lived proposal. That 2

proposal was for Barry Unit 8, which has an expected service life of 40 years. 3

Q: WHAT DID YOU DO NEXT? 4

A: After we established the reference case, we determined how the inclusion of each 5

proposed resource as a dispatch option in the reference case affected total generation cost. 6

In making this assessment of each proposal’s incremental impact to the system, we 7

modeled all generation-related costs associated with the proposed resource, including 8

capacity costs, fixed operations and maintenance (“O&M”) costs, start-up costs, and 9

natural gas transportation charges. Simulating a system dispatch of the entire Southern 10

Company fleet of generating resources, including a given proposal, enabled us to quantify 11

production cost savings (i.e., energy savings), while also capturing the projected 12

commodity fuel and variable O&M costs associated with that proposal. 13

Q: CAN YOU ELABORATE ON THE VARIOUS COST COMPONENTS YOU 14

MENTIONED ABOVE? 15

A: Capacity costs in our evaluation reflect the calculated revenue requirement or capacity 16

payment that corresponds to the fixed cost obligation for a given proposal—that is, the 17

cost to customers to construct, acquire, or contract for a generating resource that provides 18

capacity. For resources that are under contract for sales to a third party, the expected 19

sales revenues are credited against the capacity costs. 20

Fixed O&M costs are the projected fixed operating and maintenance costs 21

associated with resources. For newly constructed resources, an estimate was included as 22

part of the proposal. For acquisitions, an estimate also was included with the RFP 23

5 | P a g e

response and was initially used in the evaluation. As the evaluation process progressed, 1

however, Alabama Power refined that estimate based on its detailed investigation of the 2

proposed facility. 3

Start-up cost represents the projected cost to start a thermal generating unit, 4

accounting for the anticipated number of starts under economic dispatch and the cost 5

characteristics of the resource. For contracted resources, the per-start cost was specified 6

in the proposal. 7

Finally, the natural gas transportation charges reflect the cost of maintaining firm 8

transportation capacity adequate to serve the unit. Projections of these costs were based 9

on the RFP response itself or data developed by the Fuels Services group at SCS. 10

Q: HOW DID YOU RECONCILE THE DIFFERENCES IN UNIT LIVES AND 11

LENGTH OF PPA TERMS IN THE VARIOUS PROPOSALS? 12

A: As I explained above, the 40-year expected useful life of Barry Unit 8 dictated the length 13

of the evaluation period. We thus analyzed the economics of each proposal consistent 14

with its proposed term—or in the case of acquisitions, their expected remaining lives—15

and then performed a similar economic assessment for replacement capacity for the 16

balance of the evaluation period. 17

Q: WHAT ASSUMPTION DID YOU USE FOR THE REPLACEMENT CAPACITY? 18

A: We assumed the costs and energy benefits corresponding to a dual-fueled combustion 19

turbine. In so doing, we were able to evaluate comparably all of the proposals over the 20

40-year evaluation period. 21

Q: WERE ANY OTHER COST CONSIDERATIONS INCLUDED IN YOUR 22

ANALYSIS? 23

6 | P a g e

A: Yes. For the PPA proposals, the analysis considered an equity cost. This was necessary 1

because contracted resources are potentially subject to accounting lease treatment based 2

on the term and conditions of the PPA. The PPA payment obligations can create 3

accounting liabilities that adversely impact the Company’s effective capital structure, 4

with the extent of the impact depending on whether the lease constitutes a financial lease 5

or an operating lease. In essence, the liability is treated like debt on the Company’s 6

balance sheet, thereby resulting in a decrease in the Company’s equity ratio. 7

Accordingly, the equity component included in the analysis reflected the cost to the 8

Company to maintain the prior equity ratio and offset the negative impact caused by the 9

lease treatment of the particular PPA under study. 10

For any proposal with capacity expected to be available to the Company prior to 11

December 1, 2023, the evaluation ascribed a value for that capacity based on the 12

economic carrying cost of a combustion turbine. Our evaluation also captured the 13

capacity value associated with those proposals that offered additional capacity during the 14

winter months. 15

Q: DID YOU CONSIDER ANY COST IMPACTS UNRELATED TO GENERATION? 16

A: Yes. As part of our evaluation, we factored in any costs or benefits associated with 17

transmission system impacts resulting from a given proposal, as determined by SCS 18

Transmission. Likewise, SCS Transmission evaluated the collective impact of the entire 19

portfolio of resources. 20

Q: DID YOU PERFORM ONLY ONE SET OF ANALYSES? 21

A: No. Once a competitive tier of proposals had been identified, Alabama Power contacted 22

the RFP respondents to obtain additional information, whether through refreshed pricing 23

7 | P a g e

or further data associated with the submission. Any further data obtained by the 1

Company that was pertinent to our analysis was incorporated into subsequent evaluations. 2

In addition, the Barry Unit 8 proposal was updated to reflect adjusted pricing as well as a 3

proposal for an additional unit. That unit did not make the short list of proposals, 4

however, due to transmission investment that would have been necessary to 5

accommodate the addition of the capacity. 6

Q: HOW WERE THE EVALUATIONS OF SOLAR BESS PROJECTS 7

INCORPORATED INTO YOUR OVERALL EVALUATION? 8

A: As Mr. Kelley describes in his testimony, Alabama Power secured several proposals for 9

Solar BESS projects in connection with the completion of its review of the Renewable 10

RFP. As I noted earlier, Alabama Power performed the evaluations of those projects and 11

then supplied the results to my group. 12

Q: DID YOU WORK WITH ALABAMA POWER ON ITS ANALYSIS OF THE 13

SOLAR BESS PROJECTS? 14

A: Yes. I worked with the Forecasting and Resource Planning group to structure an analysis 15

that, while not identical to the generation cost method that I described above, nonetheless 16

captured the same cost components and yielded comparable results that could be 17

incorporated into our analysis for overall comparison and evaluative purposes. 18

Q: HOW DID YOUR ANALYSIS ACCOUNT FOR FUTURE UNCERTAINTY 19

REGARDING FUEL PRICES AND CARBON COSTS? 20

A: At the direction of the Company, we applied two additional assumptions to our analysis. 21

First, we considered the potential that natural gas prices over the evaluation period could 22

remain lower (i.e., lower gas, or “LG”) than our reference case assumption (i.e., moderate 23

8 | P a g e

gas, or “MG”). Second, we considered the impact of a $20/per ton cost associated with 1

any carbon emissions from the proposed resource option. These additional assumptions 2

yielded a total of four evaluations: MG0, MG20, LG0, and LG20. Exhibit MBL-1 3

reflects the results of these evaluations. 4

Q: HOW DID YOU ESTABLISH THE FINAL RANKINGS FOR THE PORTFOLIO? 5

A: As Exhibit MBL-1 shows, the economics of each proposal (under each of the four 6

scenarios) were captured on a net present value basis in terms of dollars per kilowatt 7

($/kW). Rather than favoring any particular scenario and biasing the outcome, the four 8

were treated as of equal likelihood. The final ranking reflects an arithmetic average of 9

the economics of each proposal under the four scenarios. 10


A: Yes. 12

Direct Testimony of M. Brandon Looney

Exhibit MBL-1

PUBLIC VERSION

Alabama Power Capacity Resource PortfolioShortlist Economic Analysis Summary

Average NPV LG0 LG20 MG0 MG20

1 Dallas County Solar plus BESS Storage PPA 68 68 ‐$40 $385 ‐$115 $19 ‐$4502 Dothan Solar plus BESS Storage PPA 68 136 ‐$39 $376 ‐$115 $22 ‐$4403 Anniston Solar plus BESS Storage PPA 68 204 ‐$30 $378 ‐$118 $26 ‐$4064 Talladega Solar plus BESS Storage PPA 68 272 $6 $418 ‐$67 $65 ‐$3935 AL Solar C plus BESS Storage PPA 68 340 $33 $477 ‐$59 $99 ‐$3856 Barry Unit 8 Turnkey Build CC 743 1,083 $157 $429 ‐$307 $523 ‐$167 Hog Bayou Energy Center (early 19Y PPA) PPA CC 238 1,321 $410 $452 $60 $631 $4988 Central Alabama Generating Station APSA CC 915 2,236 $433 $519 $35 $696 $4849 Alternate Project A APSA CC $444 $513 $39 $716 $50810 Alternate Project B PPA CC $457 $495 $138 $659 $53611 Alternate Project C PPA CT $463 $517 $270 $587 $48112 Alternate Project D PPA CT $463 $517 $270 $587 $48113 Alternate Project E PPA CT $489 $536 $298 $613 $50914 Alternate Project F PPA CC $512 $575 $176 $726 $57215 Alternate Project G PPA CC $546 $608 $200 $762 $61516 Alternate Project H PPA CC $560 $619 $254 $754 $61117 Alternate Project I PPA CC $581 $640 $268 $778 $640

Note:* Capacity rating represents the Barry Unit 8 performance after the 48‐month contractual upgrade that will result in an additional 17 MWs of capacity

Project TypeProjectRankWinter Capacity MW

$/kW NPVCumulative Capacity MW

*

PUBLIC VERSION

Alabama Power Capacity Resource PortfolioShortlist Economic Analysis Details ‐ LG0

Summer Winter PPA Term Total Capacity Capacity or Natural Pre Dec 2023 Project

Project Name Ratings Ratings Remaining Capacity Fixed Equity Start-up Gas Term Total Capacity Energy Winter Avoided Total Cost/(Benefit)MW MW Life Cost O&M Cost Cost FT Equalization Cost Credit Savings Capacity Transmission Benefits $/kW

Dothan Solar plus BESS 68 68 28 481 106 376Anniston Solar plus BESS 68 68 20 665 288 378Dallas County Solar plus BESS 68 68 28 509 124 385Talladega Solar plus BESS 68 68 28 493 75 418Barry Unit 8 685 743 40 1,220 792 429Hog Bayou Energy Center (early 19Y PPA) 222 238 19 1,096 644 452AL Solar C plus BESS 68 68 20 649 172 477Alternate Project B 1,083 589 495Alternate Project A 1,061 548 513Central Alabama Generating Station 890 915 24 987 469 519Alternate Project C 644 128 517Alternate Project D 644 128 517Alternate Project E 658 123 536Alternate Project F 867 292 575Alternate Project G 911 303 608Alternate Project H 854 235 619Alternate Project I 885 245 640

Costs ($/kW) Benefits ($/kW)

PUBLIC VERSION

Alabama Power Capacity Resource PortfolioShortlist Economic Analysis Details ‐ LG20



Barry Unit 8 685 743 40 1,221 1,528 -307Anniston Solar plus BESS 68 68 20 574 692 -118Dothan Solar plus BESS 68 68 28 433 548 -115Dallas County Solar plus BESS 68 68 28 461 576 -115Talladega Solar plus BESS 68 68 28 445 512 -67AL Solar C plus BESS 68 68 20 560 619 -59Central Alabama Generating Station 890 915 24 902 867 35Alternate Project A 979 941 39Hog Bayou Energy Center (early 19Y PPA) 222 238 19 993 933 60Alternate Project B 912 774 138Alternate Project F 761 585 176Alternate Project G 805 605 200Alternate Project H 679 425 254Alternate Project I 710 442 268Alternate Project C 471 201 270Alternate Project D 471 201 270Alternate Project E 465 166 298


PUBLIC VERSION

Alabama Power Capacity Resource PortfolioShortlist Economic Analysis Details ‐ MG0



Dallas County Solar plus BESS 68 68 28 510 492 19Dothan Solar plus BESS 68 68 28 483 461 22Anniston Solar plus BESS 68 68 20 668 642 26Talladega Solar plus BESS 68 68 28 495 429 65AL Solar C plus BESS 68 68 20 652 553 99Barry Unit 8 685 743 40 1,224 700 523Alternate Project C 656 69 587Alternate Project D 656 69 587Alternate Project E 680 67 613Hog Bayou Energy Center (early 19Y PPA) 222 238 19 1,101 470 631Alternate Project B 1,094 435 659Central Alabama Generating Station 890 915 24 996 300 696Alternate Project A 1,077 361 716Alternate Project F 872 146 726Alternate Project H 866 111 754Alternate Project G 915 154 762Alternate Project I 896 118 778


PUBLIC VERSION

Alabama Power Capacity Resource PortfolioShortlist Economic Analysis Details ‐ MG20



Dallas County Solar plus BESS 68 68 28 483 933 -450Dothan Solar plus BESS 68 68 28 456 896 -440Anniston Solar plus BESS 68 68 20 617 1,024 -406Talladega Solar plus BESS 68 68 28 468 861 -393AL Solar C plus BESS 68 68 20 603 988 -385Barry Unit 8 685 743 40 1,224 1,240 -16Central Alabama Generating Station 890 915 24 949 466 484Alternate Project C 579 98 481Alternate Project D 579 98 481Hog Bayou Energy Center (early 19Y PPA) 222 238 19 1,038 540 498Alternate Project A 1,029 521 508Alternate Project E 594 84 509Alternate Project B 1,018 482 536Alternate Project F 808 236 572Alternate Project H 788 177 611Alternate Project G 852 237 615Alternate Project I 819 179 640


PUBLIC VERSION

1 | P a g e


ALABAMA POWER COMPANY ) PETITION

)

Petitioner )

) Docket No. ________

DIRECT TESTIMONY OF CHRISTINE M. BAKER

ON BEHALF OF ALABAMA POWER COMPANY


A. My name is Christine Baker. I currently serve as the Director of Regulatory Pricing & 2

Costing Services for Alabama Power Company (“Alabama Power” or “Company”). My 3

business address is 600 North 18th Street, Birmingham, Alabama 35203. 4

Q: PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND. 5

A. I graduated from Auburn University in 1993 with a Bachelor of Industrial Engineering 6

degree. I began my career at Alabama Power in 1994 in the Marketing department. I 7

progressed through various areas including Load Research and Pricing becoming a Team 8

Leader in Pricing in 2005 and the Manager of Pricing and Costing in 2012. I assumed 9

my current role as Director in 2014. 10

Q: DESCRIBE YOUR PROFESSIONAL RESPONSIBILITIES AS DIRECTOR OF 11

REGULATORY PRICING & COSTING SERVICES. 12

A: As Director, my responsibilities involve oversight of the Company’s pricing and costing 13

functions. The former includes the design, modification and administration of all 14

available customer rate schedules; the latter includes the annual cost of service study and 15

associated load research along with various costing analyses that support the pricing 16

options offered to customers. 17

2 | P a g e


A: The purpose of my testimony is to describe the timing and manner by which costs 2

associated with the proposed generating resources reflected in the Company’s petition for 3

a certificate of convenience and necessity will be recovered if the Company is granted the 4

requested authorization. 5

Q. ARE THERE EXISTING RETAIL RATE MECHANISMS THAT INFORM THE 6

MANNER OF COST RECOVERY, IF THE REQUESTED AUTHORIZATION IS 7

GRANTED? 8

A: Yes. Alabama Power has on file with the Alabama Public Service Commission 9

(“Commission”) rate mechanisms that apply to the cost recovery of the projects identified 10

in the petition. These include Rate CNP – Adjustment for Commercial Operation of 11

Certificated New Plant (“Rate CNP”); Rate ECR – Energy Cost Recovery Rate (“Rate 12

ECR”); and Rate RSE – Rate Stabilization and Equalization Factor (“Rate RSE”). 13

Copies of these rates are attached to my testimony at Exhibit CMB-1. 14

Q. HOW DOES THE COMPANY DETERMINE WHICH COST RECOVERY 15

MECHANISM TO APPLY? 16

A: Each of the foregoing rates has terms and conditions that govern its application relative to 17

the projects proposed for certification. The Company also relies on direction from the 18

Commission as to the recovery of certain costs through either Rate CNP or Rate ECR; as 19

to the selection of an allocation formula when required; or in the event certain accounting 20

authorizations are necessary. 21

Q. CAN YOU EXPAND ON THE PROVISIONS OF THE RATES AND HOW THEY 22

OPERATE? 23

3 | P a g e

A: Rate CNP prescribes the manner for cost recovery of certificated new plant, power 1

purchase arrangements (“PPA”) and certain mandated expenditures. Rate CNP is divided 2

into three parts. Part A (the CNP Factor for Certificated Generating Facilities, or “Plant 3

Factor”) addresses the non-mandated costs associated with newly certificated generating 4

resources built or acquired by Alabama Power. Part B (the CNP Factor for Certificated 5

Power Purchase Arrangements, or “Purchase Factor”) addresses certain Commission-6

directed costs associated with certificated PPAs. Part C (the CNP Factor for Compliance 7

with Governmental Mandates, or “Compliance Factor”) addresses costs incurred due to 8

defined governmental mandates associated with each of the certificated resources. 9

Rate ECR provides for cost recovery, through an Energy Cost Recovery Factor 10

(“ECR Factor”) of defined energy-related costs associated with the certificated projects 11

(e.g., fuel costs), along with any other costs or credits that are a part of, or directly related 12

to, a certificated PPA, as directed by the Commission. 13

Rate RSE provides for the rate treatment of general costs not otherwise captured 14

above, arising from the authorization being sought through the Company’s petition. 15

Q. HOW WILL THESE COST RECOVERY MECHANISMS APPLY TO EACH OF 16

THE PROPOSED RESOURCES? 17

A: I will start with the Barry Unit 8 project, which is discussed in detail in the testimony of 18

Mr. Bush. For Barry Unit 8, a specified portion of the associated cost recovery would be 19

incorporated pursuant to Rate CNP Part A. The CNP Plant Factor would initiate the 20

recovery of costs effective for billings starting with the second calendar month after 21

commercial operation of the facility, which is targeted for November 1, 2023. 22

Thereafter, the revenues derived from this initial factor and the associated costs would be 23

4 | P a g e

reflected in the Company’s annual filing under Rate RSE. The amount of the CNP Plant 1

Factor would include the revenue requirement for the average retail net plant balance, 2

excluding any portion attributable to compliance with governmental mandates 3

recoverable under the CNP Compliance Factor. The factor also would include the retail 4

portion of the plant’s operation, maintenance and depreciation expenses, excluding those 5

expenses recoverable under Rate ECR and the CNP Compliance Factor. This total retail 6

revenue requirement would then be allocated to the respective rate schedules subject to 7

Rate CNP in accordance with the allocation formula selected by the Commission. In this 8

respect, the Company is requesting that the Commission specify use of the Revenue 9

Allocation formula, consistent with Paragraph (8) of Rate CNP Part A, as the facility is 10

being certificated based on a capacity need. I would also note here that the Company 11

would expect to record construction work in progress costs incurred prior to the issuance 12

of an order on certification to meet the targeted in-service date. The Company intends to 13

submit a discrete proposal respecting such recovery in the coming weeks. 14

Q. YOU REFERENCED CERTAIN COSTS BEING EXCLUDED FROM THE 15

DEVELOPMENT OF THE CNP PLANT FACTOR. CAN YOU ELABORATE ON 16

THESE EXCLUSIONS? 17

A: The reasonably identifiable costs of the Barry Unit 8 facility attributable to compliance 18

with governmental mandates (e.g., the unit’s cooling tower and selective catalytic 19

reduction) and the associated operating and maintenance expenses would be recovered 20

through the CNP Compliance Factor. The annual filing of the CNP Compliance Factor 21

would include the revenue requirement for the average retail net plant balance 22

attributable to compliance with governmental mandates, plus the associated retail portion 23

5 | P a g e

of the plant’s operation, maintenance and depreciation expenses, all for the applicable 1

compliance year. The total retail revenue requirement for the compliance year would 2

then be allocated to the respective rate schedules according to the revenue allocation 3

formula set forth in Rate CNP Part C. Finally, all associated energy costs, as defined by 4

Rate ECR, would be recoverable in accordance with the rate. 5

Q. DOES THAT COMPLETE THE DESCRIPTION OF COST RECOVERY FOR 6

THE PROPOSED BARRY UNIT 8? 7

A: Yes. 8

Q. PLEASE DESCRIBE THE COST RECOVERY PROCESS FOR THE PROPOSED 9

ACQUISITION OF THE CENTRAL ALABAMA GENERATING STATION? 10

A: Upon closing of the acquisition (which is targeted for mid-2020), Alabama Power will 11

assume an existing power sales agreement under which the full output of the facility 12

remains committed to a third-party until May 2023. With the entirety of the plant so 13

committed, Rate CNP Part A would not need to operate until that power sales agreement 14

terminates. Accordingly, the Company requests that the effective date of the CNP Plant 15

Factor be postponed from 2020 until the existing power sales agreement term ends in 16

May 2023. The Company also would request that the Commission authorize it to 17

depreciate or amortize, as appropriate, the total cost associated with the acquisition as of 18

the closing over the entire life of the facility and establish any required regulatory assets. 19

This accounting treatment will result in an alignment of the entire cost of the acquisition 20

with the full benefits that customers will realize from the addition of capacity and 21

increased reliability over the complete period of its service to customers. 22

6 | P a g e

Q: HOW DOES THE COMPANY PROPOSE TO TREAT THE ACQUSITION 1

DURING THE INTERIM PERIOD? 2

A: Given the Company’s requested postponement of the effective date of the CNP Plant 3

Factor, the acquisition costs, along with the revenues associated with the power sales 4

agreement, would flow through Rate RSE during the interim three-year period. As the 5

revenues associated with the power sales agreement are expected to more than offset the 6

acquisition costs during this time, this will result in downward pressure on customer 7

rates. 8

Q: WHAT WOULD TRANSPIRE FOLLOWING THE END OF THE INTERIM 9

PERIOD? 10

A: Once the power sales agreement has ended, the CNP Plant Factor would become 11

effective in June 2023, in accordance with the provisions of Rate CNP Part A. The 12

amount of the CNP Plant Factor would include the revenue requirements on amounts 13

allocated to retail associated with the average of acquisition costs, net of amortization and 14

depreciation and net changes to plant assets, determined in accordance with the rate and 15

consistent with the factor’s June 2023 effective date. The revenue requirement for the 16

CNP Plant Factor would exclude any reasonably identifiable portion of the average retail 17

net plant balance attributable to components of the plant required for compliance with 18

governmental mandates recoverable under the CNP Compliance Factor. The CNP Plant 19

Factor also will include the retail portion of the plant’s operation, maintenance and 20

depreciation expenses, excluding those expenses recoverable under Rate ECR and not 21

otherwise recoverable through the CNP Compliance Factor. This total retail revenue 22

requirement for the upcoming 12 months would then be allocated to the respective rate 23

7 | P a g e

schedules subject to Rate CNP in accordance with the allocation formula selected by the 1

Commission in its order certificating the plant. In this respect, and consistent with its 2

request for Barry Unit 8, the Company is requesting that the Commission specify the 3

Revenue Allocation formula. 4

Q. DOES THAT COMPLETE THE INCORPORATION OF COST RECOVERY 5

FOR THE PROPOSED ACQUISITION OF THE CENTRAL ALABAMA 6

GENERATING STATION? 7

A: No. Beginning in June of 2023, the reasonably identifiable portions of the plant 8

attributable to compliance with governmental mandates (e.g., cooling tower, certain 9

catalysts), along with the associated operating, maintenance and depreciation expenses, 10

will be recovered through the CNP Compliance Factor, in the same manner as I described 11

above for Barry Unit 8. In addition to the compliance costs, all fuel costs associated with 12

the operation of the plant beginning in June of 2023 would be incorporated into the 13

Energy Cost Recovery Factor through the terms of Rate ECR. During the interim period, 14

fuel costs are borne by the purchaser being served under the power sales agreement. 15

Q. HOW WILL THE COMPANY INCORPORATE THE COSTS ASSOCIATED 16

WITH THE PROPOSED PPAS? 17

A: The costs associated with the PPAs will be recovered pursuant to the terms of both Rate 18

CNP Part B through the CNP Purchase Factor and Rate ECR through the purchased 19

energy portion of the Energy Cost Recovery Factor. The Commission will specify which 20

costs will be included under each of these rates. As the terms of the PPAs vary (one PPA 21

concerning the output of the Hog Bayou Energy Center (“Hog Bayou”) and five PPAs 22

regarding the output from the solar/battery energy storage systems (“Solar/BESS”) 23

8 | P a g e

projects), the Commission will specify which costs will be included under each of these 1

rates. In addition, the PPAs create an equity cost as discussed in Mr. Looney’s 2

testimony. The Company would request that the Commission confirm the inclusion of 3

such costs as recoverable through Rate RSE. 4

Q: DESCRIBE HOW THE HOG BAYOU PPA WILL BE TREATED. 5

With respect to the Hog Bayou PPA, the applicable costs for incorporation into rates 6

include capacity and energy costs under the PPA, along with any other costs and credits 7

that may arise under the terms and conditions. The Company is requesting that the 8

Commission specify all capacity-related costs (i.e., the capacity payments) associated with 9

the PPA be recovered under the terms of the CNP Purchase Factor. The retail revenue 10

requirement for the CNP Purchase Factor year will be allocated to the respective rate 11

schedules in accordance with the revenue allocation formula set forth in Rate CNP Part B. 12

The Hog Bayou PPA is scheduled to commence contemporaneously with certification. If 13

the certificate is obtained prior to the February 1, 2020 filing date under Rate CNP Part B 14

for the upcoming Purchase Factor year, the Company would reflect these costs in that 15

filing. If the certificate is issued after the February 1, 2020 filing date, the Company would 16

elect to include the cost in the recovery balance, to be reflected in the next scheduled 17

Purchase Factor year as allowed by Rate CNP Part B. The Company is also requesting that 18

the Commission specify the recovery of the Hog Bayou PPA energy-related costs (e.g., 19

energy payments, variable operation and maintenance expenses, fuel costs) in accordance 20

with the provisions of Rate ECR and the Energy Cost Recovery Factor. 21

Q. WILL THE COSTS FOR THE FIVE SOLAR/BESS PPAS BE INCORPORATED 22

IN THE SAME MANNER? 23

9 | P a g e

A: These PPAs have varying start dates from 2022 through 2024, but the payment structure 1

is the same: a bundling of both solar- and BESS-related costs into a combined energy 2

payment, without specific delineation. As Mr. Kelley explains in his testimony, however, 3

the BESS component of each project provides capacity to the Company. Based on the 4

Company’s analysis, 38 percent of the combined energy payments associated with the 5

Solar/BESS PPAs are reasonably attributable to the cost of the BESS. Accordingly, the 6

Company is requesting that the Commission specify that 38 percent of the Solar/BESS 7

payments be directed for recovery through the CNP Purchase Factor, with the remainder 8

recovered pursuant to the terms of the Energy Cost Recovery Factor as energy-related 9

payments are incurred. The Solar/BESS expenses directed to the CNP Purchase Factor 10

for the applicable Purchase Factor year in which the PPA commences will be reflected in 11

an appropriate Replacement Factor, as required under the rate, and allocated to the 12

respective rate schedules according to the revenue allocation formula as set forth in Rate 13

CNP Part B. Lastly, the Company would recover costs associated with interconnecting 14

the projects to the Company’s electric system under Rate RSE. 15

Q: WHAT DOES THE COMPANY INTEND TO DO WITH RENEWABLE ENERGY 16

CERTIFICATES (“RECS”) ASSOCIATED WITH THE SOLAR/BESS 17

PROJECTS? 18

A: As with other projects that generate RECs, the Company has reserved the right to retire 19

the RECs on behalf of customers or make sales of RECs to its customers or to other third 20

parties. Any revenues associated with REC sales would be credited to Rate ECR to the 21

benefit of customers. 22

10 | P a g e

Q. DOES THE FOREGOING DISCUSSION ADDRESS THE RATE TREATMENT 1

FOR ALL OF THE SUPPLY-SIDE RESOURCES BEING PROPOSED? 2

A: Yes. 3

Q. WHAT ARE THE ESTIMATED RATE PRESSURES OF THE PROPOSED PLAN? 4

A: Assuming certification of the proposed resources in 2020, the associated costs and 5

estimated fuel savings would be incorporated into rates through the various rate 6

mechanisms described and over the timeframes I have discussed. Any necessary 7

adjustments would occur over an approximately four-year period, with specific actions 8

corresponding with the time-frame under which the resources and PPAs are brought into 9

service. Once all supply-side resources are in service, the Company estimates that the net 10

pressure on rates through the various mechanisms would equate to approximately $4 per 11

month on a typical residential bill. This estimated impact takes into account both the cost 12

of the new resources as well as energy savings (primarily fuel savings) expected to result 13

as these additions are used to displace higher-cost output from other facilities. 14

Q. DOES THIS CONCLUDE YOUR TESTIMONY? 15

A. Yes, it does. 16

Direct Testimony of Christine M. Baker

Exhibit CMB-1

RATE CNP

ADJUSTMENT FOR COMMERCIAL OPERATION OF CERTIFICATED NEW PLANT

By order of the Alabama Public Service Commission dated March 9, 2017 in Dockets #18117 and #18416. Effective March 23, 2017 for application to April, 2017 billings and thereafter.

PAGE 1 of 11

EFFECTIVE DATE March 23, 2017

REVISION Seventh

AVAILABILITY

Same as the specific rate incorporating this Rate CNP by reference.

APPLICABILITY

Applicable as an integral part of each rate schedule of the Company in which reference is made to this Rate CNP.

EXPLANATORY STATEMENT

Rate CNP is designed to adjust monthly billings to recover certain costs associated with: (i) a generating facility developed by the Company, or the acquisition of a generating facility by the Company, for which a certificate of convenience and necessity has been issued by the Alabama Public Service Commission; and (ii) a power purchase arrangement for which a certificate of convenience and necessity has been issued by the Alabama Public Service Commission; and (iii) compliance with laws, regulations, or other such governmental mandates impacting the Company’s facilities or operations. The billing mechanism to recover such costs is hereinafter referred to as the “CNP Adjustment”, and comprises the CNP Plant Factor, the CNP Purchase Factor, and the CNP Compliance Factor. Rate CNP is made a part of each of the rate schedules of the Company to which Rate CNP is applicable and any modification, amendment or replacement of such rate schedules. All bills rendered under such rate schedules of the Company will be subject to the CNP Adjustment.

DERIVATION OF CNP ADJUSTMENT

The CNP Adjustment to be applied to each kilowatt-hour in the affected monthly billings shall be the CNP Factor associated with certificated generating facilities (as described in Subpart A below), the CNP Factor associated with certificated power purchase arrangements (as described in Subpart B below), and the CNP Factor associated with governmental mandates (as described in Subpart C below). Those factors shall be derived as follows:

A. CNP FACTOR FOR CERTIFICATED GENERATING FACILITIES

The CNP Factor associated with certificated generating facilities (“CNP Plant Factor”) is a factor intended to initiate the recovery of costs associated with additional generating facilities that have been certificated by the Commission, whether developed or acquired by the Company (“Certificated Plant”). Thereafter, the revenues derived from this initial factor and the costs associated with the new generating facility will be reflected in the Company’s annual filing under Rate RSE. The amount of this CNP Plant Factor shall be determined by the following steps:

RATE CNP



PAGE 2 of 11


REVISION Seventh

(1) Projected electric plant in service balances associated with the Certificated Plant

(excluding any reasonably identifiable portion of such balances attributable to compliance with governmental mandates, which portion is recoverable pursuant to Part C) will be determined for the upcoming twelve (12) month period, beginning with the month immediately following the month in which commercial operation commences or the acquisition closes, as applicable (“Plant Factor Year”). For an acquisition, the additions to electric plant in service shall be the Company’s capital investment to acquire the facility, as approved in the Commission’s certification order.

(2) The plant balances calculated in Item (1), less (a) any projected balance of associated

accumulated depreciation and (b) any projected balance of associated accumulated deferred income taxes for the upcoming twelve (12) month period in accordance with the rules and requirements of the Internal Revenue Service, will be summed and divided by twelve (12) to derive the average net plant balance. The average net plant balance (less any portion of that balance associated with unit power sales agreements or other wholesale power arrangements of a similar nature) will then be separated to retail electric service by application of the retail electric investment factor set forth in the most recent cost-of-service study filed by the Company with the Commission to derive the “average retail net certificated plant balance”.

(3) The weighted cost of capital shall be determined by using the embedded costs of debt

and preferred stock for the month in which commercial operation of the certificated plant commences or, for an acquisition, the month in which the transaction closes. Weighting shall be accomplished by applying the corresponding capital structure ratios. For purposes of this calculation, the weighted cost of common equity component shall be the “adjusting point” of the WRRCE under Rate RSE including any applicable performance-based adder. In the absence of such an adjusting point, the weighted cost of common equity component shall be based on the allowed rate of return on common equity as then reflected in the most recent rate order of the Commission. To the extent investments attributable to the certificated plant are eligible for tax exempt financing, the amount of facilities financed at the tax exempt rates will be reflected at the embedded tax exempt rate(s) and the balance of investments financed by taxable debt will utilize the Company’s embedded cost of debt, excluding tax exempt debt.

(4) The income tax requirement associated with the preferred stock and common equity

weighted cost of capital shall be determined by the formula: [combined tax rate ÷ (1 - combined tax rate)] X (preferred stock weighted cost + common equity weighted cost). The combined tax rate shall be calculated as

RATE CNP



PAGE 3 of 11


REVISION Seventh

F + S - 2FS

1 - FS

where “F” is the statutory Federal income tax rate and “S” is the statutory State income tax rate.

(5) The revenue requirement for the average retail net certificated plant balance will be

computed by the multiplication of Item (2) above times the total of Items (3) and (4) above.

(6) Projected operation and maintenance expenses and depreciation expense associated

with the Certificated Plant (excluding fuel, which is recoverable pursuant to Rate ECR, and any reasonably identifiable portion of such expenses attributable to compliance with governmental mandates, which portion is recoverable pursuant to Part C) will be determined for the Plant Factor Year. These expenses (less any portion of the expenses associated with unit power sales agreements or other wholesale power arrangements of a similar nature directly related to the facility) will then be separated to retail electric service by application of the retail expense allocation factor set forth in the most recent cost-of-service study filed by the Company with the Commission.

(7) The “retail revenue requirement” (“RRR”) will be computed by the addition of Items (5)

and (6) above. (8) The retail revenue requirement (Item (7) above) will be allocated to each of the

respective rate schedules that are subject to this Rate CNP in accordance with one of the formulas set out below, and will be applied to that rate schedule so as to adjust the kilowatt-hour charges thereunder. The Commission will specify the applicable allocation formula in its order certificating the new generating facility or acquisition.

ALLOCATION FORMULA

Option (i): Energy Allocation

(RRR) = CNP Plant Factor kWht

T = T =

RATE CNP



PAGE 4 of 11


REVISION Seventh

Option (ii): Revenue Allocation

BRs (RRR) BRt = CNP Plant Factor kWhs

Where, for the Plant Factor Year:

RRR = Retail revenue requirement. BRs = The projected base rate revenue from each respective rate schedule

that is subject to this Rate CNP for the Plant Factor Year. “Base rate revenue” from any such rate schedule excludes amounts from Rate ECR and Rate T.

BRt = The projected total base rate revenues from all rate schedules that are

subject to this Rate CNP for the Plant Factor Year. Such base rate revenues exclude amounts from Rate ECR and Rate T.

kWhs = The projected kilowatt-hour sales by rate schedule for the Plant Factor

Year. kWht = The projected total kilowatt-hour sales for the Plant Factor Year.

The resulting amount (rounded to the nearest .0001 cent) shall be the CNP Plant Factor for that respective rate schedule.

B. CNP FACTOR FOR CERTIFICATED POWER PURCHASE ARRANGEMENTS

The CNP Factor associated with power purchase arrangements (“CNP Purchase Factor”) is based upon the costs as specified for inclusion by the Commission in the respective orders granting certification. The amount of the CNP Purchase Factor shall be determined by the following steps: (1) The estimated cost of all such purchases (excluding the energy cost recoverable

through Rate ECR and any other costs directed for recovery elsewhere by the Commission) will be projected for the twelve (12) month period from April 1 through March 31 (“Purchase Factor Year”).

RATE CNP



PAGE 5 of 11


REVISION Seventh

(2) The amount from Item (1) will be separated to retail electric service by application of the

retail expense allocation factor set forth in the most recent cost-of-service study filed by the Company with the Commission.

(3) The amount of any over-recovered or under-recovered balance will be projected for the

end of the immediately preceding Purchase Factor Year. (4) The “retail revenue requirement” will be computed by the addition of Items (2) and (3)

above. (5) The retail revenue requirement (Item (4) above) will be allocated to each of the

respective rate schedules that are subject to this Rate CNP in accordance with the formula set out below and will be applied to that rate schedule so as to adjust the kilowatt-hour charges thereunder.

ALLOCATION FORMULA

BRs (RRR) BRt = CNP Purchase Factor kWhs

Where, for the Purchase Factor Year:


that is subject to this Rate CNP for the Purchase Factor Year. “Base rate revenue” from any such rate schedule excludes amounts from Rate ECR and Rate T.


subject to this Rate CNP for the Purchase Factor Year. Such base rate revenues exclude amounts from Rate ECR and Rate T.

kWhs = The projected kilowatt-hour sales by rate schedule for the Purchase

Factor Year. The resulting amount (rounded to the nearest .0001 cent) shall be the CNP Purchase Factor for that respective rate schedule.

RATE CNP



PAGE 6 of 11


REVISION Seventh

C. CNP FACTOR FOR COMPLIANCE WITH GOVERNMENTAL MANDATES

The CNP factor associated with governmental mandates (“CNP Compliance Factor”) is

based upon the cost of compliance with: (i) environmental laws, regulations, and/or other mandates having a similar purpose (“environmental mandates”); and (ii) laws, regulations and/or other mandates directed to the utility industry involving security, reliability, safety, sustainability, or similar considerations impacting the Company’s facilities or operations (“other mandates”). The amount of the CNP Compliance Factor shall be determined by the following steps:

(1) Projected in service plant balances associated with capital additions to certificated

generating facilities, or other capital additions, as made necessary to comply with governmental mandates will be determined for the upcoming twelve (12) month period from January 1 to December 31 (“compliance cost year”).

(2) The plant balances calculated in Item (1) (less (a) any projected balance of associated

accumulated depreciation, (b) any projected balance of associated accumulated deferred income taxes, and (c) any projected balance of accumulated tax credits) will be summed and divided by twelve (12) to derive the “average net compliance plant balance” (“average plant balance”). The average plant balance (less any portion of that balance associated with unit power sales agreements or other wholesale power arrangements of a similar nature) will then be separated to retail electric service by application of jurisdictional separation factors set forth in the most recent cost-of-service study filed by the Company with the Commission to derive the “average retail net compliance plant balance” (“average retail plant balance”).

(3) The weighted cost of capital shall be determined by use of the embedded costs of debt

and preferred stock as of September 30 prior to the compliance cost year and weighting shall be accomplished by applying the capital structure ratios then prevailing. For purposes of this calculation, the weighted cost of common equity component shall be the “adjusting point” of the WRRCE under Rate RSE including any applicable performance-based adder. In the absence of such an adjusting point, the weighted cost of common equity component shall be based on the allowed rate of return on common equity as then reflected in the most recent rate order of the Commission. To the extent investments attributable to these governmental mandates become eligible for tax exempt financing, the amount of facilities financed at the tax exempt rates will be reflected at the embedded tax exempt rate(s) and the balance of investments financed by taxable debt will utilize the embedded cost of debt excluding the tax exempt debt.

(4) The income tax requirement associated with the preferred stock and common equity

weighted cost of capital shall be determined by the formula: [combined tax rate ÷ (1 –

RATE CNP



PAGE 7 of 11


REVISION Seventh

combined tax rate)] X (preferred stock weighted cost plus common equity weighted cost). The combined tax rate shall be calculated as

T = F + S – 2FS

1 – FS Where “F” is the statutory Federal income tax rate and “S” is the statutory State income

tax rate. (5) The revenue requirement for the average retail plant balance will be computed by the

multiplication of Item (2) above times the total of Items (3) and (4) above. (6) Projected operation and maintenance expenses and depreciation expense that are

attributable to governmental mandates will be determined for the compliance cost year. These expenses (less any portion of the expenses associated with unit power sales agreements or other wholesale power arrangements of a similar nature) will then be separated to retail electric service by application of the expense jurisdictional separation factor set forth in the most recent cost-of-service study filed by the Company with the Commission.

(7) The amount of any over-recovery or under-recovery (“true-up calculation”) will be

determined with respect to Items (5) and (6) above based upon the actual average retail plant balance, actual expenses, actual depreciation expense, and actual retail kilowatt-hours, as opposed to the projections of these inputs that were used to derive the CNP Compliance Factor. The true-up calculation will be performed for the current compliance cost year using actual data through September 30 and projections of the inputs for the remainder of the calendar year. A true-up calculation will also be performed for the period of October 1 through December 31 of the prior compliance cost year, together with other appropriate adjustments to reflect actual data to the extent practicable.

(8) The “retail revenue requirement” (“RRR”) will be computed by the addition of Items (5),

(6) and (7) above.

(9) The retail revenue requirement from Item (8) above will be allocated to each of the respective rate schedules that are subject to this Rate CNP in accordance with the formula set out below and will be applied to that schedule so as to adjust the kilowatt-hour charges thereunder.

RATE CNP



PAGE 8 of 11


REVISION Seventh

ALLOCATION FORMULA

BRs (RRR) BRt = CNP Compliance Factor kWhs Where, for the compliance cost year,


that is subject to this Rate CNP for the upcoming compliance cost year. “Base rate revenue” from any such rate schedule excludes amounts from Rate ECR and Rate T.


subject to this Rate CNP for the upcoming compliance cost year. Such base rate revenues exclude amounts from Rate ECR and Rate T.

kWhs = The projected kilowatt-hour sales by rate schedule for the upcoming

compliance cost year.

The resulting amount (rounded to the nearest .0001 cent) shall be the CNP Compliance Factor for that respective rate schedule.

APPLICABLE CNP ADJUSTMENT

The CNP Plant Factor, the CNP Purchase Factor, and the CNP Compliance Factor shall become effective as follows:

(1) With respect to the CNP Plant Factor determined pursuant to Subpart A of this Rate

CNP: (a) For each rate schedule subject to this Rate CNP, the Company will file with the

Commission the CNP Plant Factor (along with appropriate supporting materials) to be separately applied to each kilowatt-hour thereunder. This filing will be made on or before the first business day of the month following the month in which the applicable event described below occured. i. For filings related to certificated plant developed by the Company, the event is

commercial operation.

RATE CNP



PAGE 9 of 11


REVISION Seventh

ii. For filings related to a certificated acquisition of an operational facility, the

event is the closing of the acquisition. iii. For filings related to a certificated acquisition of a facility still under construction,

the event is the closing of the acquisition or commercial operation, whichever is later.

(b) The CNP Plant Factor filed by the Company will be effective for billings starting with the second calendar month following the occurrence of the applicable event, and shall remain in effect thereafter. Each CNP Plant Factor shall be incorporated in the charge for each kilowatt-hour under each of the rate schedules that are subject to this Rate CNP.

(c) The Company will make relevant books and records available for inspection by

the Commission Staff as needed to resolve any questions concerning the development of any CNP Plant Factor hereunder. With respect to Company generating facilities under construction, the Company will provide the Commission Staff with monthly status reports. Reasonable arrangements will be made to preserve the confidentiality of any competitively-sensitive or proprietary data that is made available or accessed through such reports or during any such inspection.

(2) With respect to the CNP Purchase Factor determined pursuant to Subpart B of this

Rate CNP: (a) By February 1 of each year, the Company will file with the Commission a CNP

Purchase Factor (along with appropriate supporting materials) for each rate schedule to be separately applied to each kilowatt-hour under each such rate schedule that is subject to this Rate CNP. In the event a certificated power purchase will begin or end during the projected twelve (12) month period (April 1 through March 31), the Company will also include in its filing a “replacement factor” that recognizes the effect of such new or terminated purchase.

(b) The CNP Purchase Factor filed by February of a given year will be effective for

April billings of that year and will continue in effect through March billings of the following year; provided, however, that in the event the Company’s filing includes a replacement factor, that replacement factor will become effective for the billing month immediately following the month in which the certificated power purchase begins or terminates (in lieu of the initial factor) and will continue in effect for billings through the following March.

RATE CNP



PAGE 10 of 11


REVISION Seventh

(c) In the event a power purchase that will begin during the projected twelve (12)

month period is certificated by the Commission after the CNP Purchase Factor is filed, the Company may either: (i) file a new CNP Purchase Factor that recognizes the effect of the newly-certificated power purchase; or (ii) include the cost associated with that purchase in the balance described in Item (3) until such purchase can be reflected in Item (1) of the next scheduled CNP Purchase Factor calculation. Unanticipated terminations or other such events will be handled in the same manner.

(d) The Company will make relevant books and records available for inspection by

the Staff as needed in order to resolve any questions from the Commission or its Staff concerning application of any CNP Purchase Factor developed hereunder. Reasonable arrangements will be made to preserve the confidentiality of any competitively-sensitive or proprietary data that is accessed during any such inspection.

(e) In the event this Rate CNP is terminated or withdrawn, the CNP Purchase Factor

(including related true-ups) shall nevertheless continue to operate until all previously certificated power purchase arrangements have expired or otherwise been terminated in accordance with their terms.

(3) With respect to the CNP Compliance Factor determined pursuant to Subpart C of this

Rate CNP:

(a) For each rate schedule subject to this Rate CNP, the Company will file with the Commission, by December 1 of each year, the CNP Compliance Factor (along with appropriate supporting materials) to be separately applied to each kilowatt-hour thereunder.

(b) Each CNP Compliance Factor filed by December 1 of a given year will be effective

for January billings of the next succeeding year and will continue in effect through December billings of that same year.

(c) Subsequent to the filing of each CNP Compliance Factor, an informal meeting will

be convened on the second Tuesday in December, as designated by the Commission, in order to review and discuss the Company’s environmental compliance activities. At this meeting, the Company will provide an overview of its environmental compliance plan for the next five (5) years, together with the estimated cost associated with the implementation of that plan. The Company will also discuss pending environmental laws, regulations or other mandates relevant to its environmental compliance activities, as well as any other matters or

RATE CNP



PAGE 11 of 11


REVISION Seventh

information that it or the Commission considers relevant and appropriate in that regard. The Company will file the above-referenced environmental compliance plan at least thirty (30) days prior to the December 1 deadline for filing the CNP Compliance Factors described in Item 3(a) above.

(d) The Company will make relevant books and records available for inspection by the

Commission Staff as needed to resolve any questions concerning the Company’s environmental compliance plan and the development of any CNP Compliance Factor hereunder. Reasonable arrangements will be made to preserve the confidentiality of any competitively-sensitive or proprietary data that is accessed during any such inspection.

ADDITIONAL REQUIREMENTS APPLICABLE

TO THE CNP PLANT FACTOR

By a comparable calculation a lessened retail revenue requirements and a per-kilowatt-hour reduction shall be computed based upon the book closing for the month in which an ownership interest in a previously certificated plant is transferred by the Company so as to remove a portion of said net plant from net plant dedicated to retail electric service. Such adjustment shall be based upon the amount of plant (net of any buy-back by the Company) transferred in excess of the amount of such net plant already allocated to the non-retail jurisdiction. Such adjustment shall be applied in each monthly billing beginning with the second calendar month following such transfer.

SPECIAL RULES

The Special Rules Governing the Operation of Rates RSE and CNP constitute an integral part of this rate.

RATE ECR ENERGY COST RECOVERY RATE By order of the Alabama Public Service Commission dated March 7, 2017 in Docket # 18148.

PAGE 1 of 6

EFFECTIVE DATE January, 2017 Billings

REVISION Third

AVAILABILITY

Same as the specific base rate schedule incorporating this Energy Cost Recovery Rate by reference.

APPLICABILITY Applicable as an integral part of each base rate schedule of the Company in which reference is made to this Rate ECR.

EXPLANATORY STATEMENT By its order in Docket #18148 (consolidating Docket #18152) issued May 29, 1981, the Alabama Public Service Commission abolished Rate FT, effective upon the replacement thereof by procedure to be defined in the rates, rules and regulations of the Commission incorporating, for application in Alabama, the Georgia fuel cost recovery system described in the order. That order also observed that it would be necessary in the transition to the new system "that the rate form be so arranged as not to constitute a revision or refiling of those general rate schedules of the Company now filed and under suspension and with respect to which the Commission must issue an order on or before October 18, 1981." To implement the Commission's May 29, 1981 order, Rate ECR (set forth below) will replace the Energy Cost Adjustment, Energy Cost Adjustment Calculation Procedure and the Special Rules Governing Administration of Rate FT, as last approved by the Commission. The tax provisions of Rate FT ("Income Tax Rate Adjustment," "General Tax Provisions," and "Adjustment for Local Taxes") continue to be effective and are designated as "Rate T."

GENERAL DESCRIPTION OF RATE

This Rate ECR is made a part of each of the base rate schedules of the Company to which Rate ECR is applicable and any modification to, amendment to or replacement of such base rate schedules. All bills rendered under such base rate schedules of the Company will be increased pursuant to the provisions of this Rate ECR and the effective Energy Cost Recovery factor calculated pursuant to this Rate ECR. This Rate ECR provides for the recovery by the Company of defined energy cost and establishes a procedure for the recovery of defined energy costs through the base rate schedules of the Company. After the development of the Energy Cost Recovery factor, it will be combined for billing purposes with the charges in the applicable rate schedule and shown as a single line item on the bill to the customer.


PAGE 2 of 6


REVISION Third

ENERGY COST RECOVERY FACTOR

CALCULATION PROCEDURE (RATE ECR FORMULA)

The Energy Cost Recovery factor to be applied to each kilowatt-hour supplied by the Company under any base rate schedule of which this Rate ECR is made a part shall be calculated in accordance with the following formula:

ECRF = ETEC + CF ETS -

Where: ECRF = Energy cost recovery factor to be applied to the retail kilowatt-hour sales during the

current billing period and computed to the nearest one-thousandth of a cent per kilowatt-hour.

ETEC = The sum of:

(1) Estimated cost of fossil fuel and emission allowances to be issued out of Accounts 151 and 158.1 and charged to Accounts 501, 509, 518 and 547 of the Uniform System of Accounts prescribed by the Alabama Public Service Commission for the current billing period (three months) at the Company's generating plants, including also the Company's portion of estimated fossil fuel cost and emission allowances at generating plants whose capacity is shared with others and the Company's portion of such estimated costs at plants owned or operated by any affiliated company.

(2) Estimated cost of nuclear fuel to be recorded in Account 518 (exclusive of any fossil fuel expense therein to be issued from Account 151) of such Uniform System of Accounts for the current billing period (three months) at the Company's generating plants, including also the Company's portion of estimated nuclear fuel cost at generating plants whose capacity is shared with others and the Company's portion of such estimated cost at plants owned or operated by any affiliated company.

(3) Estimated purchased energy cost, exclusive of capacity or demand charges, shall be that portion of the estimated cost to be recorded in Account 555 of such Uniform System of Accounts for the current billing period (three months), excluding the cost related to the generation at plants owned or operated by any affiliated company already reflected in the estimated fossil and nuclear fuel costs above, when such energy is purchased on an economic dispatch basis or, otherwise, the estimated actual identifiable fossil fuel cost issued from Account 151 and nuclear fuel cost recorded in Account 518 or the estimated average cost of such fossil and nuclear fuel when such costs are not actually identifiable; less the estimated actual


PAGE 3 of 6


REVISION Third

identifiable cost of fossil and nuclear fuel (together with costs, gains, or losses associated with emission allowances) recovered through estimated inter-system sales or the estimated average cost of such fossil and nuclear fuel when such costs are not actually identifiable. Estimated purchased energy cost also includes any other cost or credit that is part of, or directly related to, a certificated power purchase arrangement if the Commission, in its order certifying the arrangement, so directs the inclusion of such cost or credit in Rate ECR.

(4) Gains, losses and costs associated with Company’s utilization of futures, options and over the counter derivatives (including, without limitation, futures contracts, puts, calls, caps, floors, collars, and swaps) for the purpose of hedging its energy and fuel costs.

(5) Gains, losses and costs recorded in Account 456 associated with sales of natural gas that are attributable to operating considerations at the Company’s electric generating facilities.

ETS = Estimated total energy sales of the Company for the current billing period (three

months), to be divided into the aforesaid sum (ETEC) so as to derive a factor (computed to the nearest one-thousandth of a cent per kilowatt-hour).

CF = The correction factor for prior periods represents the adjustment that is necessary to

adjust prior estimates to actual data. This adjustment shall be computed as follows: Accumulate and total the actual monthly data in the categories of cost referred to in ETEC above. Deduct from this amount of total energy cost the following: (a) The energy cost recovery applicable to the wholesale customers, and (b) the energy cost recovery billed to the retail customers. The net amount represents the under- or over-recovery of energy cost applicable to retail customers for the month. The monthly amounts shall be accumulated through the end of the third month preceding the current billing period (three months). Then add the estimated under- or over-recovery of energy cost applicable to retail customers for the second (to be adjusted to Actual at the hearing if data available) and first months preceding the current billing period. This summation produces a dollar amount which, when divided by the estimated retail energy sales for the current billing period (three months), constitutes the correction factor (CF). The CF is computed to the nearest one-thousandth of a cent per kilowatt-hour.

In the development of the initial Energy Cost Recovery factor, the transition from the Energy Cost Adjustment contained in Rate FT to this Rate ECR must be recognized. Therefore, it will be necessary to estimate (later to be adjusted to actual) the under- or over-recovery for May and June 1981. This estimate shall be included as the correction factor in the initial Energy Cost Recovery factor. This estimate shall be computed as presently provided for in Rate FT.


PAGE 4 of 6


REVISION Third

RULES AND REGULATION GOVERNING

APPLICATION OF ENERGY COST RECOVERY RATE These rules and regulations are applicable to and are an integral part of Rate ECR. These rules and regulations established the procedures to be used in the determination of the Energy Cost Recovery factor. 1. On or before June 10, 1981, the Company shall submit to the Commission an estimate of

energy cost and estimated sales for the three (3) calendar months beginning on July 1, 1981, and a proposed, initial Energy Cost Recovery factor computed in accordance with the calculation procedure contained in this Rate ECR, to be incorporated in base rate schedules of the Company as provided in this Rate ECR. On or before June 19, 1981, the Commission shall conduct a public hearing on the information so submitted for the purpose of determining its accuracy. The Company's testimony shall be under oath and shall, with any corrections thereto, constitute the Company's affirmative case. The Commission will issue an order on or before June 24, 1981, establishing the initial Energy Cost Recovery factor to be incorporated in the base rate schedules of the Company beginning July 1, 1981, and continuing until changed by the provisions of this Rate ECR.

2. After the initial Energy Cost Recovery factor is established, the Company can change such

Energy Cost Recovery factor because of increased or decreased energy cost only after a submittal to the commission of an estimate of the Company's energy cost and sales for the three (3) consecutive calendar months beginning forty-five (45) days following the submittal and a proposed Energy Cost Recovery factor to recover those costs adjusted as required by the provisions of the Rate ECR Formula and subsection 4 of these rules and regulations. The Company shall submit its proposed Energy Cost Recovery factor and testimony forty-five (45) days in advance of the date the new Energy Cost Recovery factor is to be made effective as a part of the base rate schedules of the Company. Not less than twenty (20) days after any such submittal or after a Commission show cause order concerning the existing Energy Cost Recovery factor, the Commission shall conduct a public hearing on the information so submitted for the purpose of determining its accuracy. The Company's testimony shall be under oath and shall, with any corrections thereto, constitute the Company's affirmative case. At any such hearing, the burden of proof to show that an increased Energy Cost Recovery factor, based on fluctuations in energy cost, is just and reasonable shall be upon the Company.

Formal intervention by customers of the Company shall be permitted. The staff of the

Commission and formal intervenors shall have the right to examine all of the Company's records used in preparation of the testimony and exhibits of the Company, to cross-examine the Company's witnesses and present rebuttal testimony. If the staff of the Commission or any formal intervenors intend to submit rebuttal testimony recommending a


PAGE 5 of 6


REVISION Third

different estimate of the Energy Cost Recovery factor, such testimony shall be reduced to writing and delivered to the Company five (5) days in advance of the scheduled hearing date. Following such hearing, the Commission shall issue an order stating the Energy Cost Recovery factor to be used by the Company during the next three (3) consecutive calendar months, or until changed as provided in this paragraph. The hearing shall be completed and submitted for issuance of an order within thirty-five (35) days from the Company's initial submittal. Should the Commission fail to issue such an order by the forty-fifth (45th) day after the Company's submittal, the Energy Cost Recovery factor proposed by the Company thereupon be deemed effective.

3. The Company shall compute, record and report to the Commission the monthly and

accumulated over or under-recovery of actual energy cost resulting from application of the Energy Cost Recovery factor as soon as available.

4. It is the express purpose of this Rate ECR to allow the Company to recover the energy

costs specifically identified in the Rate ECR Formula. Accordingly, the Rate ECR Formula contains an adjustment which requires the Company to collect or refund any accumulated under-recovery or over-recovery resulting from the difference between actual energy cost and revenues recovered pursuant to the estimated Energy Cost Recovery factor established by the Commission pursuant to this Rate ECR. At any time the Commission orders a change in the Energy Cost Recovery factor, recognition will be given to such accumulated over or under-recoveries so as to provide that the Company will neither recover more than nor less than its actual energy cost as defined in the ECR formula contained in this Rate ECR. Further, to provide for an orderly transition from the Energy Cost Adjustment contained in Rate FT to this Rate ECR, the under or over-recoveries under the Energy Cost Adjustment contained in Rate FT for the months of May and June, l981, will be incorporated and recognized in the accumulated over and under-recoveries provided for in the Rate ECR formula contained in this Rate ECR.

5. The Commission shall disallow and make appropriate adjustments for any reported energy

cost that is the result of illegal or clearly imprudent conduct on the part of the Company. 6. All Commission orders establishing a changed Energy Cost Recovery factor pursuant to

this Rate ECR shall contain the Commission's findings of fact and conclusions of law upon which the Commission's action is based. Such order shall be deemed a final order subject to judicial review under Alabama law.

7. The Commission shall not prohibit or limit the operation of this Rate ECR to the extent it permits rate increases or decreases to adjust for increased or decreased purchase power costs where such increased or decreased purchase power costs shall have become effective under the procedures of a Federal regulatory agency or under a contract approved by a Federal regulatory agency. Any subsequent refunds received by the Company with


PAGE 6 of 6


REVISION Third

respect to such increased purchase power costs which become effective under procedures of a Federal regulatory agency, or otherwise, shall be refunded by the Company to its customers in the manner directed by the Commission.

8. In submitting any estimate of energy costs under this Rate ECR, the Company shall

disclose the name and address of each person, firm or corporation from whom the Company expects to purchase fuel, or the transportation of fuel, during the period covered by such estimate. Each such submittal shall also disclose, when applicable, any financial interests the Company has in any person, firm or corporation expected to supply fuel or transport fuel to the Company during the period covered by the estimate. It shall be the duty of the Commission to make public at each public hearing held pursuant to this Rate ECR any information disclosed by the Company pursuant to the requirements of this paragraph. It shall constitute a financial interest within the meaning of this paragraph:

(a) For any member of the Board of Directors of the Company to be a member of the

Board of Directors of a corporation supplying fuel, or transporting fuel, to the Company;

(b) For any member of the Board of Directors of the Company to be the proprietor of, or a

partner in, any business supplying fuel, or transporting fuel, to the Company; or

(c) For any member of the Board of Directors of the Company or the Company to own ten percent (10%) or more of the stock of any corporation supplying fuel, or transporting fuel, to the Company.

9. The procedures provided for in Rate ECR and these Rules and Regulations are for the

purpose of calculating, at a hearing, the energy costs of the Company, which are recoverable in full (but no more) as part of the application of Rate ECR and the rates to which it applies. Therefore, the submittals of the Company to initiate the calculation procedures and hearing are not "new schedules" subject to suspension within the meaning of Section 37-1-81, Code of Alabama 1975. The procedures and hearing are governed by the 45-day time limitation hereinabove specified.

RATE RSE RATE STABILIZATION AND EQUALIZATION FACTOR

By orders of the Alabama Public Service Commission in Dockets #18117 and #18416. Effective for December 1982 billings and thereafter; modified effective for July 1985 billings and thereafter; modified effective for April 1990 billings and thereafter; modified effective for April 1998 billings and thereafter; modified effective May 1, 2002 for application to March 2003 billings and thereafter; modified effective October 16, 2005 for application to January 2007 billings and thereafter; modified effective September 20, 2013 for application to January 2014 billings and thereafter; modified effective June 1, 2018, for application to January 2019 billings and thereafter.

PAGE

1 of 4 EFFECTIVE DATE

June 1, 2018 REVISION

Seventh

AVAILABILITY

Same as the specific rate incorporating this Rate RSE by reference.

APPLICABILITY Applicable as an integral part of each rate schedule of the Company in which reference is made to this Rate RSE.

EXPLANATORY STATEMENT It is the purpose of Rate RSE to lessen the impact, frequency and size of retail rate increase requests by permitting the Company, through the operation of a filed and approved rate, to adjust its charges more readily to achieve the rate of return allowed it in the rate order of the Commission. By provisions in the rate, the charges are increased if projections for the upcoming year show that the designated rate of return range will not be met and are decreased if such projections show that the designated rate of return range will be exceeded. Other provisions limit the impact of any one adjustment (as well as the impact of any consecutive increases), and also test whether actual results exceeded the weighted equity return range.

APPLICATION OF RATE RSE AND CALCULATION PROCEDURES

Monthly billings on and after January 2019 shall be adjusted (increased or decreased) by the application of a rate stabilization and equalization factor ("RSE Factor") in accordance with the procedure herein described. By December 1, 2018, and by each December 1 thereafter, the Company's weighted return on projected average common equity, separated to retail electric service ("WRRCE"), shall be computed annually for the upcoming twelve-month period ending December 31 (such twelve-month period being the “rate year”). The WRRCE shall be computed on the basis of cost estimates and budgets prepared by the Company in the ordinary course of its business and in a manner consistent with the Uniform System of Accounts through the tabulations specified on Appendix B hereto. If the resulting WRRCE is less than 5.75% or more than 6.15% (5.75% - 6.15% being "the weighted equity return range"), then monthly bills under the respective rate schedules subject to this Rate RSE shall be increased or decreased by amounts per kilowatt-hour necessary, in total, to restore the WRRCE to 5.98% (the "adjusting point" in the weighted equity return range) plus a possible performance-based adder of 0.07%.



PAGE



Seventh

The performance-based adder shall be added to the adjusting point if, at the time of the annual Rate RSE filing, the Company satisfies at least one of the following criteria: (i) an “A” credit rating equivalent with at least one of the recognized rating agencies, or (ii) a ranking in the top third of the most recent customer value benchmark survey or its successor in function. The above-described increases and decreases are accomplished through the application of an RSE Factor, which is developed by the formula contained in Appendix A hereto. Both Appendix A and Appendix B constitute an integral part of this Rate RSE. The RSE Factor shall be revised annually for application to billings beginning January of each rate year if the WRRCE computed with respect to that rate year is outside of the weighted equity return range. (For example, any revision of the RSE Factor for use beginning with January 2019 billings would be derived from the WRRCE computed for the upcoming twelve-month period ending December 31, 2019.) For monthly billings commencing January 2019 and thereafter, the kilowatt-hour charges under the respective rate schedules shall be adjusted by applying the current annual revision (if any) of the RSE Factor to the existing kilowatt-hour charges, as theretofore adjusted for the cumulative effect of all prior RSE Factors and other adjustments (such as, for example, adjustments pursuant to Rate CNP).

ADJUSTMENT LIMITATIONS Consecutive increases derived by the annual operation of Rate RSE shall be limited such that adjustments for any consecutive two-year period, when averaged together, do not exceed four percent (4%). Thus, the limitation governing any such consecutive increase shall be the percentage that, when combined with the percentage adjustment that was made applicable to monthly billings for the current year, produces an average of four percent (4%). Notwithstanding the foregoing, the maximum increase in any one year associated with the operation of Rate RSE shall not exceed five percent (5%) of the projected total retail revenues of the Company (“RR”) for the rate year used to compute the WRRCE. Hypothetical examples of the application of these limitations in the context of consecutive years include: 4.5% and 3.5%; 5.0% and 3.0%; 3.2% and 4.8%; 3.0% and 5.0%, and so forth.

PRIOR YEAR ACTUAL RESULTS

On or before March 1 of each year, the Company shall submit to the Commission a calculation of its actual weighted return on average retail common equity (“AWRRCE”) for the immediately preceding calendar year (“review year”) under this Rate RSE.



PAGE



Seventh

This AWRRCE will be calculated in the same manner as set forth under Appendix B, except that actual data will be substituted for the projected data used to develop the WRRCE for the same twelve-month period. If the AWRRCE derived through this calculation is above the weighted equity return range, then the Company shall determine the amount of revenue that caused the AWRRCE for the review year to exceed the top end of the designated range. The amount of revenue to be returned to customers shall be determined in the manner set forth in Appendix A (“refund factor”) and, unless otherwise directed by the Commission, shall be refunded to retail customers by rate schedule. The implementation of any refunds to customers shall be accomplished through the application of credits on customer billings for the month of April following the review year.

OTHER LIMITATIONS AND PROVISIONS

Jurisdictional Allocations. In the computation of WRRCE and the RSE Factor, it is necessary for jurisdictional purposes that allocations be made as between electric and nonelectric operations and then as between retail electric service and electric service other than retail. For the applications of this Rate RSE, the Company will prepare and file by May 1 of each year, a cost-of-service study based upon data from the prior calendar year. The most recently filed cost-of-service study shall be used in the computation of WRRCE, RSE Factor, and the Refund Factor. Corrections or revisions proposed thereto, if not accepted by the Company, may be made the subject of a limited complaint proceeding under the Special Rules Governing Operation of this Rate. If such a complaint proceeding is instituted and not completed before the next annual RSE computation, the lower of the existing factors or the newly filed factors shall be used in computations under this Rate until such complaint proceeding is resolved.



PAGE



Seventh

COMMISSION-REQUIRED ADJUSTMENTS

Advertising Expense. In its decision in Alabama Power Co. v. Alabama Public Service Commission, 359 So. 2d 776 (Ala. 1978), the Supreme Court of Alabama recognized advertising expense as an allowable expense for a utility company in a ratemaking proceeding. However, as an additional constraint upon expenditures by the Company, in each computation under Rate RSE one-half (1/2) of the amounts in Accounts 909 and 930.1 will be disallowed.

Lobbying Expense. The expenses of lobbying are appropriately charged to Account 426.4 and will not be charged to the ratepayer in any computation of this Rate RSE or otherwise.

Donations. In its decisions in Alabama Power Co. v. Alabama Public Service Commission, 359 So. 2d 776 (Ala. 1978) and Alabama Power Co. v. Alabama Public Service Commission, 390 So. 2d 1017 (Ala. 1980), the Supreme Court of Alabama has ruled that charitable donations (Account 426.1) cannot be proper expenses of a utility company for ratemaking purposes. Unless and until this matter is dealt with otherwise by legislation or subsequent court rulings, the Company will not undertake to move such expenditures from "below-the-line" to "above-the-line" status in any computation under this Rate RSE or in any ratemaking proceeding. Civic Club Dues. Civic club dues are properly charged to Account 426.5 and will not be charged to the ratepayer in any computation of this Rate RSE or otherwise.

SPECIAL RULES The Special Rules Governing Operation of Rates RSE and CNP constitute an integral part of this Rate.

RATE RSE – APPENDIX A RATE STABILIZATION AND EQUALIZATION FACTOR


PAGE

Page 1 of 4 EFFECTIVE DATE


Seventh

DEVELOPMENT OF RSE FACTOR

The rate stabilization and equalization factor (RSE Factor) will be initially developed, and thereafter changed whenever the WRRCE for the rate year is not within the weighted equity return range. The RSE Factor shall be calculated for each respective affected rate schedule in accordance with the formula set out below and shall be applied in that schedule so as to adjust the kilowatt-hour charges as the same may have been adjusted by any previous applications of Rate RSE: If ((AROR - WRRCE)/CEP)(RCE) BRs 1 - T is greater (L% x RR) BRt = RSE Factor* RR than L%, then KWHs If ((AROR - WRRCE)/CEP)(RCE) 1 - T is equal to, ((AROR-WRRCE)/CEP)(RCE) BRs = RSE Factor* RR or less than 1 - T BRt L%, then KWHs *Rounded to nearest 0.0001 cent Where, for the twelve-month period constituting the rate year, AROR = Adjusting point of Weighted Equity Return Range, plus any earned performance-

based adder. WRRCE = Projected weighted return on average retail common equity. CEP= Projected common equity percentage of capital structure. RCE = Projected average retail common equity. T = Combined Federal and State income taxes = F + S - 2 FS 1 - FS F being the effective statutory Federal income tax rate and S being the effective

statutory State income tax rate.



PAGE



Seventh

RR = Projected total retail revenues from sale of electricity for the rate year. L% = The applicable percentage limitation for the rate year. BRs = The projected base rate revenue from each respective retail rate schedule for the rate year. "Base rate revenue" from any schedule excludes amounts from Rate

ECR and Rate T. BRt = The projected total base rate revenues from all retail rate schedules for the rate year.

Such base rate revenues exclude amounts from Rate ECR and Rate T. KWHs = The projected kilowatt-hour sales by retail rate schedule for the rate year.

DEVELOPMENT OF REFUND FACTOR

The refund factor for the review year will be developed whenever the AWRRCE exceeds the top of the weighted equity return range (TROR). The refund factor shall be calculated for each affected rate schedule in accordance with the formula set forth below. The application of bill credits derived hereunder (or such other disposition as may be directed by the Commission) shall fully satisfy the Company’s refund requirement under this Rate RSE. If an upward adjustment under Rate RSE (or an upward adjustment in lieu of Rate RSE) did not occur in the review year, then calculate REF as follows: If AET ≤ 0.005 REF = (((AET)(0.25))/ACEP)(ARCE) 1-T If AET > 0.005 and ≤ 0.010

REF = ((0.00125+((AET-0.005)(0.40)))/ACEP)(ARCE) 1-T If AET > 0.010 and ≤ 0.015 REF = ((0.00325+((AET-0.010)(0.75)))/ACEP)(ARCE) 1-T



PAGE



Seventh

If AET > 0.015 REF = ((0.007+(AET-0.015))/ACEP)(ARCE) 1-T If an upward adjustment under Rate RSE (or an upward adjustment in lieu of Rate RSE) occurred in the review year, then calculate REF as follows: If AET ≤ 0.0075 REF = (((AET)(0.50))/ACEP)(ARCE) 1-T If AET > 0.0075 REF = ((0.00375+(AET-0.0075))/ACEP)(ARCE) 1-T

In all review years, calculate the AREF as follows: If AWRRCE > (ACEP)(0.138), then

AREF = ((AWRRCE-((ACEP)(0.138)))/ACEP)(ARCE) 1-T

Otherwise, AREF = 0 Develop the refund factor, If REF ≥ AREF, then BRsa (REF) BRta = Refund Factor* KWHs Otherwise, BRsa (AREF) BRta = Refund Factor* KWHs *Rounded to nearest 0.0001 cent



PAGE



Seventh

Where, for the review year, AWRRCE = Actual weighted return on average retail common equity. TROR = Top of weighted equity return range. AET = Amount exceeding top = AWRRCE - TROR ACEP = Actual common equity percentage of capital structure. ARCE = Actual average retail common equity. REF = Amount to refund to customers. AREF = Alternate amount to refund to customers. T = Combined Federal and State income taxes = F + S - 2 FS 1 – FS F being the effective statutory Federal income tax rate and S being the effective

statutory State income tax rate. BRsa = The billed base rate revenue recorded from each respective retail rate schedule for

the review year. “Base rate revenue” from any schedule excludes amounts from Rate ECR and Rate T.

BRta = The total billed base rate revenues recorded from all retail rate schedules for the

review year. Such base rate revenues exclude amounts from Rate ECR and Rate T.

KWHs = The kilowatt-hour sales recorded for each respective retail rate schedule for the

review year.

RATE RSE – APPENDIX B RATE STABILIZATION AND EQUALIZATION FACTOR


PAGE



Seventh

DETERMINATION OF PROJECTED AVERAGE RETAIL COMMON EQUITY (RCE) AS OF DECEMBER 31, ___________:

Column 1 Column 2

Total Amount Non-Electric

(Projected 12-mo. avg. bal.) (Projected 12-mo. avg. bal.)

Investment

1. Electric Plant in Service (Account 101) $ __________ (E) $ __________

2. Electric Plant Held for Future Use (Account 105) __________

3. Construction Work in Progress-Electric

(Account 107) __________ __________

4. Accumulated Provision for Depreciation and

Amortization of Electric Utility Plant-Credit

(Accounts 108 and 111) __________ (E)

5. Electric Plant Acquisition Adjustments-Net

(Accounts 114 and 115) __________

6. Steam Heat Plant (Account 118) __________ __________

7. Accumulated Provision for Depreciation of

Steam Heat Plant-Credit (Account 119) __________ __________

8. Nuclear Fuel-Net (Account 120) __________

9. Nonutility Property (Account 121) __________ __________

10. Accumulated Provision for Depreciation

and Amortization of Nonutility

Property-Credit (Account 122) __________ __________

11. Investment in Subsidiary Companies (Account 123) __________ __________

12. Other Investments (Account 124) __________ __________

13. Fuel Stock (Account 151) __________ __________

14. Materials and Supplies (Account 154) __________ __________

15. Merchandise (Account 155) __________ __________

16. Allowance Inventory (Account 158) __________

17. Total $ ================ $ ================



PAGE



Seventh

DETERMINATION OF PROJECTED AVERAGE RETAIL COMMON EQUITY (RCE)

AS OF DECEMBER 31, ___________:

Column 1 Column 2

Total Amount Non-Electric

(Projected 12-mo.avg. bal.) (Projected 12-mo. avg. bal.)

18. Electric Investment Percent

(Line 17, [Col. 1 - Col. 2 less UPS

Investment of $_____] ÷ Col. 1) __________ % (D)

19. Retail Electric Investment Factor __________ %

20. Retail Investment Separation Factor

(Line 18 x Line 19) __________ %

Common Equity Percentage of Capital Structure

21. Common Equity (Accounts 201, 211 and 216) $ __________

22. Debt (Accounts 221-226 and 231) __________

23. Preferred Stock (Accounts 204-207 and 214) __________

24. Total (Line 21 + Line 22 + Line 23) $ ===============

25. Common Equity Percentage of Capital Structure (CEP) =============== %

(Line 21/Line 24)

Retail Common Equity (RCE)

26. Retail Common Equity (Line 20 x Line 21) $ ================



PAGE



Seventh

DETERMINATION OF PROJECTED RETAIL NET INCOME FOR THE 12 MONTHS ENDING DECEMBER 31, _____________: Total Electric Retail Electric (Projected 12 mos. total) (Projected 12 mos. total)

Electric Operating Revenue:

1. Sale of Electricity (Accounts 440-448) $ __________ $ __________ (A)

2. Other Operating Revenues

(Accounts 450-456) __________ __________ (B)

3. Total Operating Revenues (Line 1 + Line 2) __________ __________

Electric Expenses:

4. Electric Operation and Maintenance Expenses

(Accounts 401 and 402) __________

5. Electric Depreciation and Amortization

Expenses (Accounts 403-407) __________

6. Taxes Other than Income Taxes

(Account 408.1) __________

7. Other Revenue Credits (Accounts 447-02xxx,

447-04xxx, 454 except

454-00904, and 456 except 456-00953) __________ (A), (B)

8. Electric Expenses Other than Income Taxes

(Lines 4, 5, and 6 - Line 7) __________

9. Operating Income before Income Taxes

(Line 3 - Line 8) __________

10. Income Taxes (Accounts 409-411) __________

11. Retail Expense Allocation Factor __________ %

12. Retail Expenses Other Than Income Taxes

(Line 8 - UPS Expenses of $_____) x Line 11 __________ (D)

13. Retail Operating Income before Income

Taxes (Line 3 - Line 12) __________

14. Retail Income Taxes (Line 13 ÷ Line 9) x Line 10 __________

15. Net Retail Electric Operating Income (Line 13 - Line 14) __________



PAGE



Seventh

DETERMINATION OF PROJECTED RETAIL NET INCOME FOR THE 12 MONTHS ENDING

DECEMBER 31, ______________:

Total Electric Retail Electric (Projected 12 mos. total) (Projected 12 mos. total)

Allowance for Funds Used During Construction

16. Electric Allowance for Funds Used During

Construction (AFUDC) - Gross __________

17. Retail Electric Allocation Factor __________ %

18. Retail Electric AFUDC (Line 16 - UPS

Investment AFUDC of $_____) x Line 17 __________ (D)

Interest Income

19. Interest Revenue (Accounts 419-00001,

419-00034, 419-00038 and 419-00066

through 419-00068) (net of tax) __________

20. Retail Interest Income (Line 19 x Retail

Investment Separation Factor) __________ %(C) __________

Interest Expense and Preferred Dividends:

21. Interest Expense (Accounts 427-431) __________

22. Preferred Dividends (Account 437) __________

23. Total Interest Expense and Preferred

Dividends [(Line 21 + Line 22) x Retail Investment

Separation Factor] __________ %(C) __________

Commission-Required Adjustments

24. Commission-Required Adjustments (net of tax) __________

25. Retail Commission-Required Adjustments

(Line 24 x Retail Expense Allocation Factor) __________ % __________

Retail Net Income Available for Common Equity (RNI)

26. Retail Net Income Available for Common Equity

(Line 15 + Line 18 + Line 20 - Line 23 + Line 25) $ ================

Weighted Return on Average Retail Common Equity

RNI x CEP = WRRCE __________ %

RCE



PAGE



Seventh

Notes: Note (A): To conform with cost-of-service procedures, amounts included in Account 447

(Sales for Resale) associated with Non-Territorial Sales for Resale (subaccounts 447-02xxx and 447-04xxx) are excluded from Line 1 and included in Line 7.

Note (B): To conform with cost-of-service procedures, the total of Accounts 450 (Forfeited Discounts), 451 (Miscellaneous Service Revenues), 453 (Sales of Water and Water Power), subaccount 454-00904 (Rent from Leased Property on Customers' Premises-Other), and subaccount 456-00953 (Miscellaneous Electric Revenues-Return Check Charge) is included on Line 2. The remaining subaccounts for Accounts 454 (Rent from Electric Property) and 456 (Other Electric Revenues) are included in Line 7.

Note (C): Developed on Line 20 of retail common equity computation. Note (D): To conform with cost-of-service procedures and to afford proper recognition of

investment and associated allowance for funds and expenses associated with Unit Power Sales to Nonassociated Utilities, the investment and associated allowance for funds and expenses associated with such sales have been accounted for on Line 18 of RCE calculation and on Lines 12 and 18 of RNI calculation.

Note (E): For purposes of Rate RSE, the capitalization of asset retirement costs shall be excluded from Account 101 (Electric Plant in Service) and the associated depreciation shall be excluded from Account 108 (Accumulated Provision for Depreciation of Electric Utility Plant) pursuant to Accounting for Asset Retirement Obligations.

1644447.1

CONFIDENTIALITY AGREEMENT

THIS CONFIDENTIALITY AGREEMENT (“Agreement”), entered into and made effective as of the [__] day of [_______________], is by and between Alabama Power Company (“Company”) and Reviewing Representatives, as defined below, acting on behalf of [ ] (collectively “Intervenors”).

W I T N E S S E T H:

WHEREAS, the Company has filed a petition for a certificate of convenience and necessity with the Alabama Public Service Commission in Docket No. [ ] (the “Petition”); and

WHEREAS, the non-public version of the Petition includes information that is proprietary and confidential to the Company—and for certain information to one or more third parties as well—the public disclosure of which could materially and adversely affect the effective and successful conduct of the Company’s and/or the third parties’ businesses, result in competitive disadvantage and business injury to them, and/or cause harm to other customers of the Company; and

WHEREAS, Intervenors have sought leave to intervene in Docket No. [ ] and have been, or are expected to be granted party status, with all rights and privileges as directed by the Commission in accordance with applicable law; and

WHEREAS, in connection therewith, Intervenors desire access to the non-public version of the Petition and other Confidential Information, as defined below; and

WHEREAS, to avoid any harmful outcomes, the Company desires to put in place this Agreement in order to safeguard against the intentional or inadvertent disclosure of any and all Confidential Information to third parties; and

WHEREAS, as evidenced by their execution of this Agreement, Intervenors are willing to accept and be legally bound by the terms and conditions set forth herein, as a precondition for the production of Confidential Information by Company to Intervenors.

NOW, THEREFORE, in consideration of the mutual promises and covenants made herein, and with the intent to be legally bound hereby, Company and Intervenors agree as follows:

1. As used in this Agreement, “Confidential Information” means: (i) the non-public version of the Petition, including all portions of the supporting testimony and exhibits marked Confidential; and (ii) all information provided or made available to Reviewing Representatives of Intervenors by the Company that the Company has designated, orally or in writing, as Confidential Information. Confidential Information also includes “Attorneys’ Eyes Only” information, as designated by Company in accordance with Paragraph 5 below. The Company has the discretion to determine what Confidential Information it will make available under this Agreement, and the Intervenors and their Reviewing Representatives agree to accept the

1644447.1

Company’s decision as to what information it makes available, as well as the Company’s determination that such information is Confidential Information. However, the Company’s determination shall in no way diminish or restrict Intervenors’ discovery rights as permitted by the Alabama Public Service Commission.

2. Confidential Information shall not include information which:

(i) is or becomes generally available to the public other than as a result of acts by a Reviewing Representative, anyone to whom a Reviewing Representative supplies the Confidential Information, or anyone whose possession of the Confidential Information also is governed by a confidentiality agreement;

(ii) is disclosed to a Reviewing Representative by a third party which is not, to the knowledge of Reviewing Representative, prohibited from disclosing such information by a contractual, legal or other duty to Company; or

(iii) is provided to Intervenors by the Company and has not been designated “Confidential Information.”

3. In the event the Company determines that Confidential Information has been disclosed without having been so marked, the Company reserves the right to designate the Confidential Information by providing contemporaneous notice to counsel for Intervenors and, as necessary, providing a copy of the Confidential Information marked accordingly. Thereafter, such Confidential Information shall be subject to the terms and conditions of this Agreement.

4. As used in this Agreement, “Reviewing Representative” means a person who has signed a copy of this Agreement (or the attached Appendix) for purposes of reviewing or receiving Confidential Information, who is:

(i) an Intervenor who has been granted party status in Docket No. [ ] or has an application for party status pending and to which the Company has not filed an objection; provided, however, that in the event Intervenors’ application for party status is denied, then any Confidential Information provided prior to such action shall be handled in accordance with Paragraph 10;

(ii) an attorney representing said Intervenor(s);

(iii) attorneys, paralegals and other employees associated with an attorney described in item 2(ii) for purposes of Intervenors’ participation in Docket No. [ ];

(iv) an expert or consultant (or an employee of such expert or consultant) retained by Intervenors for purposes of Intervenors’ participation in Docket No. [ ]; or

(v) attorneys, paralegals and other employees of the Alabama Public Service Commission or the Office of the Attorney General of the State of Alabama.

1644447.1

Intervenors shall provide the Company with a list of all of its Reviewing Representatives and shall promptly update such list when new Reviewing Representatives are added.

5. Attorneys’ Eyes Only: For Confidential Information that is proprietary and confidential to third parties, the Company reserves the right to designate such information Attorneys’ Eyes Only and limit production of such information only to the following:

(i) an attorney representing an Intervenor who has been granted party status in Docket No. [ ];

(ii) attorneys, paralegals and other employees of the Alabama Public Service Commission or the Office of the Attorney General of the State of Alabama.

6. The Reviewing Representatives agree to protect and maintain the confidentiality of all Confidential Information and shall not, directly or indirectly, in whole or in part, or in any derivative form:

(i) use such Confidential Information for any purpose other than in connection with Intevenors’ direct participation in Docket No. [ ]; provided, however, that the use of Confidential Information in connection with the above shall include appropriate protections to maintain the confidential nature of the information including, without limitation, the employment of redactions, sealed pleadings, and other such measures; or

(ii) disclose such Confidential Information to any person who is not a signatory to this Agreement, without regard to whether such person is an officer, employee or staff member of Intervenors; holds a membership interest in or affiliation with Intervenors; or is officer, employee or staff member of an affiliate or subsidiary of Intervenors.

7. In the event a Reviewing Representative becomes aware of an actual or potential breach of this Agreement including, without limitation, the actual or potential disclosure or review of Confidential Information by any person who has not executed this Agreement, or any actual or potential unauthorized use of Confidential Information, Intervenors or the Reviewing Representative shall, to the extent practicable, take steps to prevent such actual or potential breach and shall also promptly give written notice to the Company of such facts.

8. Intervenors and each of their Reviewing Representatives expressly understand and agree that in the event of any breach or threatened breach of this Agreement, the Company could be irreparably and immediately harmed and may not be made whole by monetary damages and may be entitled to, in addition to any other remedy to which it may be entitled at law or in equity, seek injunctive relief. In the event of a breach of this Agreement, the Company shall be entitled to all remedies available at law or in equity, including all costs and expenses (including reasonable attorneys’ fees) incurred by the Company in connection with efforts to enforce the terms and conditions of this Agreement.

9. Company and Reviewing Representatives agree that this Agreement shall be construed in accordance with the laws of the State of Alabama, without reference to its conflict of

1644447.1

laws principles. Company and Reviewing Representatives further agree to submit to the jurisdiction of the state and federal courts situated in Jefferson County, Alabama to adjudicate any dispute arising out of relating to this Agreement including, but not limited to, the enforcement of rights under Paragraph 8. BOTH COMPANY AND REVIEWING REPRESENTATIVES WAIVE, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT TO A TRIAL BY JURY IN RESPECT OF ANY PROCEEDINGS ARISING OUT OF RELATING TO THIS AGREEMENT. Any judgment awarded may be enforced by any court having competent jurisdiction thereof.

10. Intervenors and each of their Reviewing Representatives expressly understand and agree that by gaining access to Confidential Information in accordance with this Agreement, all such Reviewing Representatives shall be deemed ineligible, for a period of three (3) years from the date of such access, from:

(i) any involvement in the development of proposals to, or the negotiation and preparation of any contracts or other arrangements with, the Company or any of its affiliates within the Southern Company system related to the supply of capacity, energy, and/or renewable attributes associated with any generating facility; or

(ii) any participation in a Request for Proposal (“RFP”), or any consultation with or representation of a participant in an RFP, that is extended by the Company or any of its affiliates within the Southern Company system and that solicits proposals for such supply of capacity, energy, and/or renewable attributes associated with any generating facility.

11. All Confidential Information in the possession of Reviewing Representatives at this conclusion of proceedings related to Docket No. [ ] shall be returned or destroyed at the election of the Company, including all originals, copies, translations, notes, or any other form of said material, as well as any and all written, printed, or other material or other information derived from the Confidential Information. To the extent a Reviewing Representative is instructed to destroy the Confidential Information, the Reviewing Representative shall promptly provide written or electronic confirmation to the Company that the requirements of this paragraph have been satisfied.

12. The obligations and commitments established by this Agreement, except where otherwise provided, shall remain in full force and effect for five (5) years following the effective date.

13. This Agreement may be executed in counterparts, each of which is deemed an original, but all of which together constitute one and the same instrument. Facsimile/electronic signatures hereto are deemed original signatures.

[SIGNATURE BLOCKS ON SUBSEQUENT PAGE]

1644447.1

IN WITNESS WHEREOF, the parties hereto have entered into this Agreement as of the day and year first herein above written.

[Intervenor] Alabama Power Company

Printed Name: _____________________ Printed Name: ______________________

Signature: _____________________ Signature:__________________________

Date: ____________________________ Title: ____________________________

Date: _____________________________

1644447.1

APPENDIX

List of additional Intervenors’ Reviewing Representative signatories to the foregoing Confidentiality Agreement pertaining to Confidential Information provided or made available in connection with this Agreement. Signatories below each certify that they have read the forgoing Confidentiality Agreement, understand the obligations and commitments therein, and agree to be personally bound thereby.

By: ____________________________

Name: ____________________________

Title: ____________________________

Date: _____________________________

By: ____________________________

Name: ____________________________

Title: ____________________________

Date: _____________________________

By: ____________________________

Name: ____________________________

Title: ____________________________

Date: _____________________________

By: ____________________________

Name: ____________________________

Title: ____________________________

Date: _____________________________

By: ____________________________

Name: ____________________________

Title: ____________________________

Date: _____________________________

By: ____________________________

Name: ____________________________

Title: ____________________________

Date: _____________________________

By: ____________________________

Name: ____________________________

Title: ____________________________

Date: _____________________________

By: ____________________________

Name: ____________________________

Title: ____________________________

Date: _____________________________

NOTICE OF PETITION

ALABAMA POWER COMPANY

Petitioner

PETITION: FOR A CERTIFICATE OF CONVENIENCE AND NECESSITY FOR: (I) THE CONSTRUCTION AND INSTALLATION OF COMBINED CYCLE GENERATING CAPACITY AT THE SITE OF PETITIONER’S BARRY STEAM PLANT LOCATED IN MOBILE COUNTY, ALABAMA; (II) THE ACQUISITION OF EXISTING COMBINED CYCLE GENERATING CAPACITY IN AUTAUGA COUNTY, ALABAMA; (III) THE ACQUISITION OF RIGHTS AND THE ASSUMPTION OF PAYMENT OBLIGATIONS UNDER A PURCHASED POWER AGREEMENT FOR THE OUTPUT OF COMBINED CYCLE GENERATING CAPACITY OPERATED IN MOBILE COUNTY, ALABAMA; AND (IV) THE ACQUISITION OF RIGHTS AND THE ASSUMPTION OF PAYMENT OBLIGATIONS UNDER PURCHASED POWER AGREEMENTS FOR THE OUTPUT FROM FIVE SOLAR PHOTOVOLTAIC AND BATTERY ENERGY STORAGE SYSTEMS, LOCATED IN CALHOUN, CHAMBERS, DALLAS, HOUSTON AND TALLADEGA COUNTIES; TOGETHER WITH ALL TRANSMISSION ARRANGEMENTS, STRUCTURES, SUBSTATIONS, AND FACILITIES, ENVIRONMENTAL CONTROL MEASURES, FACILITIES OR ARRANGEMENTS FOR THE HANDLING, TREATMENT, TRANSPORTATION, DELIVERY AND PROCESSING OF FUEL, AND ANY AND ALL OTHER APPLIANCES, APPURTENANCES, FACILITIES, RIGHTS, EQUIPMENT, ACQUISITIONS, COMMITMENTS AND ACCOUNTING AUTHORIZATIONS NECESSARY FOR OR INCIDENT THERETO.

DOCKET NO. _________

Interested parties are hereby advised that the above-captioned Petition by Alabama Power Company was filed with and received by the Commission on September 6, 2019.

All petitions for leave to intervene in this matter must be filed by 5:00 PM (CDT) on September __, 2019. Petitions shall set forth the basis for the proposed intervention, including the position and interest of the petitioner in the proceeding.

The above-described deadline and requirements governing interventions by any interested parties will be strictly adhered to for purposes of this proceeding. A subsequent procedural order pertaining to the hearing on the Company’s Petition, as well as any attendant matters, will be issued soon thereafter.

BY THE COMMISSION: Walter L. Thomas, Jr.Secretary

ALABAMA POWER COMPANY,3 3. Petitioner proposes to construct and install combined cycle generating...

Documents

Transcript of ALABAMA POWER COMPANY,3 3. Petitioner proposes to construct and install combined cycle generating...